Infused and coated proppant containing chemical treatment agents and methods of using same

ABSTRACT

Proppant compositions and methods for using same are disclosed herein. In particular, a proppant composition for use in hydraulic fracturing is disclosed herein. The proppant composition can contain a plurality of particulates and at least one particulate of the plurality of particulates containing a chemical treatment agent. The at least one particulate having a long term permeability measured in accordance with ISO 13503-5 at 7,500 psi of at least about 10 D. The at least one chemical treatment agent can separate from the at least one particulate when located inside a fracture of a subterranean formation after a period of time.

RELATED APPLICATION

The present application claims priority to, and the benefit of thefiling date of, U.S. Patent Application No. 62/051,719, filed Sep. 17,2014, the entire disclosure of which is incorporated herein byreference.

TECHNICAL FIELD

The present invention relates to proppant containing a chemicaltreatment agent to improve the production rates and ultimate recoveryfrom an oil or gas well.

The present invention also relates to methods for evaluating theeffectiveness and performance of a hydraulic fracturing stimulationtreatment in an oil or gas well with proppant containing a tracer.

BACKGROUND

Oil and natural gas are produced from wells having porous and permeablesubterranean formations. The porosity of the formation permits theformation to store oil and gas, and the permeability of the formationpermits the oil or gas fluid to move through the formation. Permeabilityof the formation is essential to permit oil and gas to flow to alocation where it can be pumped from the well. Sometimes the oil or gasis held in a formation having insufficient permeability for economicrecovery of the oil and gas. In other cases, during operation of thewell, the permeability of the formation drops to the extent that furtherrecovery becomes uneconomical. In such cases, it is necessary tofracture the formation and prop the fracture in an open condition bymeans of a proppant material or propping agent. Such fracturing isusually accomplished by hydraulic pressure, and the proppant material orpropping agent is a particulate material, such as sand, glass beads orceramic particles, which are carried into the fracture by means of afluid.

In the course of production, oil and gas wells oftentimes exhibit scaleformation and/or paraffin deposition that can reduce well production.Many types of chemical treatment agents have been used to prevent scaleformation and/or paraffin deposition. One technique for delivering suchchemical treatment agents downhole includes infusing porous ceramicproppant particulates with the chemical treat agent. In many instances,the chemical treatment agent must first be dissolved in an aqueous,organic or inorganic solvent to enable the infusion of the chemicaltreatment agent into the porous ceramic proppant particulates. If thechemical treatment agent is too viscous, however, this can result inlower effective amounts of the chemical treatment agent being present inthe infused proppant than desired or uneven or ineffective infusionaltogether. Dissolving the chemical treatment agent in the solvent isalso an additional step that can be costly and time consuming.

Tracers have also been used in connection with hydraulic fracturing, toprovide certain types of diagnostic information about the location andorientation of the fracture. Tracers for hydraulic fracturing have beenassociated with various carrier materials as particles from which thetracer itself is released after placement in the created hydraulicfracture. These tracer particles are oftentimes composed of a tracersubstance and a carrier wherein the carrier is comprised of starch orpolymeric materials. Carriers such as starch or polymeric materials areweak materials which if added to proppant in a hydraulic fracture cannegatively affect conductivity. Further, the densities of starch orpolymeric carrier materials are not similar to proppants typically usedin hydraulic fracturing resulting in density segregation which can leadto non-uniform distribution of the tracer chemicals in the createdfracture.

Therefore, what is needed is a method to add a chemical treatment agentto proppant particles without the need for a solvent. Also, what isneeded is a tracer carrier that does not segregate from proppant whenadded to a subterranean environment and that does not negatively impactconductivity.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention may best be understood by referring to thefollowing description and accompanying drawings that are used toillustrate embodiments of the invention. In the drawings:

FIG. 1 is a cross sectional view of a coated proppant containing achemical treatment agent disposed between a coating and a proppantparticulate in accordance with several exemplary embodiments describedherein.

FIG. 2 is a cross sectional view of a coated proppant containing achemical treatment agent dispersed within a coating in accordance withseveral exemplary embodiments described herein.

FIG. 3 is a cross sectional view of an encapsulated proppant having adegradable, non-permeable shell encapsulating a coated proppant, thecoated proppant containing a chemical treatment agent infused into aporous proppant particulate in accordance with several exemplaryembodiments described herein.

FIG. 4 is a cross sectional view of an encapsulated proppant having adegradable, non-permeable shell encapsulating an uncoated proppant, theuncoated proppant containing a chemical treatment agent infused into aporous proppant particulate in accordance with several exemplaryembodiments described herein.

FIG. 5 is a cross sectional view of an encapsulated proppant having adegradable, non-permeable shell encapsulating a coated proppant, thecoated proppant containing a chemical treatment agent disposed between aresin coating and a proppant particulate in accordance with severalexemplary embodiments described herein.

FIG. 6 is a graphical representation of a comparison of proppantpermeability for lightweight ceramic proppant, intermediate densityceramic proppant, and high density ceramic proppant.

FIG. 7 is a graphical representation of the long term permeability of astandard non-porous light weight ceramic proppant and a light weightporous ceramic proppant (at 25% porosity).

FIG. 8 depicts a perspective view of an illustrative prepack screenassembly containing a proppant pack, according to several exemplaryembodiments described herein.

FIG. 9 depicts a cross-sectional view of the prepack screen taken alongline 8-8 of FIG. 8.

FIG. 10 depicts a cross-sectional side view of an assembly having acanister placed within a tubular.

FIG. 11 depicts a cross-sectional end view of the canister shown in FIG.10.

FIG. 12 depicts a perspective view of the canister shown in FIGS. 10 and11.

FIG. 13 is a graph of an elution profile for Example 1 in terms of DTPMP(diethylenetriamine penta(methylene phosphonic acid)) in parts permillion (ppm) released as a function of time for porous ceramic proppantinfused with DTPMP and encapsulated with various coatings.

FIG. 14 is a graph of the elution profile for Example 2 in terms of theppm of DTPMP released as a function of time for porous ceramic proppantinfused with DTPMP and encapsulated with various coatings.

FIG. 15 is a graph of the elution profile for Example 3 in terms of theppm of DTPMP released as a function of time for porous ceramic proppantinfused with DTPMP and encapsulated with various coatings.

FIG. 16 is a graph of the elution profile for Example 4 in terms of theppm of DTPMP released as a function of time for porous ceramic infusedwith DTPMP and encapsulated with and without a degradable shell ofvaried thickness.

DETAILED DESCRIPTION

In the following description, numerous specific details are set forth.However, it is understood that embodiments of the invention may bepracticed without these specific details. In other instances, well-knownstructures and techniques have not been shown or described in detail inorder not to obscure the understanding of this description.Additionally, as used herein, the term “exemplary” is intended to meanserving as an illustration or example, and is not intended to indicate apreference.

The term “apparent specific gravity,” as used herein, is the weight perunit volume (grams per cubic centimeter) of the particles, including theinternal porosity. The apparent specific gravity values given hereinwere determined by the Archimedes method of liquid (water) displacementaccording to API RP60, a method which is well known to those of ordinaryskill in the art. For purposes of this disclosure, methods of testingthe characteristics of the proppant in terms of apparent specificgravity are the standard API tests that are routinely performed onproppant samples. Additionally, as used herein, the term “exemplary” isintended to mean serving as an illustration or example, and is notintended to indicate a preference.

The term “conductivity,” as used herein, is defined as the product ofthe width of the created fracture and the permeability of the proppantthat remains in the fracture.

The term “high density proppant,” as used herein, means a proppanthaving an apparent specific gravity of greater than 3.4 g/cm³.

The term “intermediate density proppant,” as used herein, means aproppant having an apparent specific gravity of from about 3.1 to 3.4g/cm³.

The term “internal interconnected porosity,” as used herein, is definedas a percentage of the pore volume, or void volume space, over the totalvolume of a porous ceramic particulate.

The term “light weight proppant,” as used herein, means a proppanthaving an apparent specific gravity of less than 3.0 g/cm³.

The term “degradable,” as used herein, means the ability of a chemicalor coating to react to dissolve or breakdown into smaller componentsunder one or more downhole conditions.

The term “infuse,” as used herein, means to inject, attach, introduce,or otherwise include a material into a porous substrate, such as aporous ceramic.

The term “ceramic,” as used herein, means any non-metallic, inorganicsolid material.

The term “ceramic proppant,” as used herein, means any man-made orsynthetic ceramic particulate(s).

The term “proppant,” as used herein, means material that includes one ormore (e.g., tens, hundreds, thousands, millions, or more) of individualproppant particulates or elements.

A proppant particulate containing one or more chemical treatment agentsfor use in hydraulic fracturing is disclosed. The one or more chemicaltreatment agents can be disposed on, attached to, coated on, infusedinto, combined with, or otherwise contained on or in the proppantparticulate to produce the proppant containing the one or more chemicaltreatment agents, also referred to as a chemical treatment agentcontaining proppant particulate. The proppant particulate can be orinclude a ceramic particulate. The ceramic particulate can include sand,porous ceramic proppant, and non-porous ceramic proppant. The chemicaltreatment agent containing proppant particulate can be coated with aresin material. The chemical treatment agent containing proppantparticulate can also be uncoated.

An encapsulated proppant particulate containing one or more chemicaltreatment agents for use in hydraulic fracturing is also disclosedherein. In one or more exemplary embodiments, the encapsulated proppantparticulate can include a chemical treatment agent containing proppantparticulate that is coated or encapsulated with a degradable outercoating, layer, or shell. This degradable outer shell, or degradableshell, can temporarily isolate the chemical treatment agent proppantparticulate from a surrounding fluid, such as a fracturing fluid, toprevent premature release of the chemical treatment agent into thefracturing fluid, for example.

A composite proppant composition for use in hydraulic fracturing is alsodisclosed. The composite ceramic proppant can contain a coatedparticulate part and a non-coated particulate part, wherein the coatedparticulate part contains a chemical treatment agent. In one or moreexemplary embodiments, the permeability and conductivity of thecomposite proppant composition is at least equal to the permeability andconductivity of the coated particulate part alone. Furthermore, in oneor more exemplary embodiments, the permeability and conductivity of thecoated particulate part alone is, at the very least, equal to thepermeability and conductivity of the composite proppant composition. Thecomposite ceramic proppant can also contain an encapsulated proppantparticulate part and a non-chemical treatment agent containing proppantparticulate part, wherein the encapsulated proppant particulate partcontains a chemical treatment agent. In one or more exemplaryembodiments, the permeability and conductivity of the composite proppantcomposition is at least equal to the permeability and conductivity ofthe encapsulated proppant particulate part alone. Furthermore, in one ormore exemplary embodiments, the permeability and conductivity of theencapsulated proppant particulate part alone is, at the very least,equal to the permeability and conductivity of the composite proppantcomposition.

In one or more exemplary embodiments, another composite ceramic proppantcomposition for use in hydraulic fracturing is disclosed. In one or moreexemplary embodiments, the composite ceramic proppant contains anon-porous particulate part and a porous ceramic particulate part,wherein the porous ceramic particulate is infused with or otherwisecontains a chemical treatment agent. Furthermore, in one or moreexemplary embodiments, the permeability and conductivity of thecomposite ceramic proppant composition is at least equal to thepermeability and conductivity of the non-porous particulate part alone.

The particulate part, or proppant particulate, can be ceramic proppant,sand, resin coated sand, plastic beads, glass beads, and other ceramicor resin coated proppants. Such proppant particulates can bemanufactured according to any suitable process including, but notlimited to continuous spray atomization, spray fluidization, dripcasting, spray drying, or compression. Suitable proppant particulatesand methods for manufacture are disclosed in U.S. Pat. Nos. 4,068,718,4,427,068, 4,440,866, 5,188,175, 7,036,591, 8,865,631 and 8,883,693,U.S. Patent Application Publication No. 2012/0227968, and U.S. patentapplication Ser. Nos. 14/502,483 and 14/802,761, the entire disclosuresof which are incorporated herein by reference, the entire disclosures ofwhich are incorporated herein by reference.

FIG. 1 is a cross sectional view of a coated proppant 100 containing achemical treatment agent 102 disposed between a coating 104 and aproppant particulate 106 in accordance with one or more embodiments. Alayer 108 of chemical treatment agent 102 can be formed between thecoating 104 and the proppant particulate 106. For example, the layer 108of chemical treatment agent 102 can surround and/or be deposited on anouter surface 107 of the proppant particulate 106. The layer 108 ofchemical treatment agent 102 can coat or cover at least about 10%, atleast about 30%, at least about 50%, at least about 70%, at least about90%, at least about 95%, or at least about 99% of the entire outersurface area of the proppant particulate 106. For example, the layer 108of chemical treatment agent 102 can coat or cover about 100% of theentire outer surface area of the proppant particulate 106. The coating104 can coat or cover at least about 10%, at least about 30%, at leastabout 50%, at least about 70%, at least about 90%, at least about 95%,or at least about 99% of the entire outer surface area of the layer 108of chemical treatment agent 102 disposed on the proppant particulate106. For example, the coating 104 can coat or cover about 100% of theentire outer surface area of the proppant particulate 106 that is coatedor covered by the layer 108 of chemical treatment agent 102 such thatthe layer 108 is disposed between the particulate 106 and the coating104. The coating 104 can include any suitable resin material and/orepoxy resin material as disclosed herein. The coating 104 can bedegradable or non-degradable.

According to several exemplary embodiments, the chemical treatment agent102 is present on the proppant particulate 106 in any suitable amount.According to several exemplary embodiments, the coated proppant 100contains at least about 0.01 wt %, at least about 0.1 wt %, at leastabout 0.5 wt %, at least about 1 wt %, at least about 2 wt %, at leastabout 4 wt %, at least about 6 wt %, or at least about 10 wt % chemicaltreatment agent 102 based on the total weight of the coated proppant100. According to several exemplary embodiments, the coating 104 ispresent on the proppant particulate 106 in any suitable amount.According to several exemplary embodiments, the coated proppant 100contains about 0.01 wt %, about 0.2 wt %, about 0.8 wt %, about 1.5 wt%, about 2.5 wt %, about 3.5 wt %, or about 5 wt % to about 8 wt %,about 15 wt %, about 30 wt %, about 50 wt %, or about 80 wt % resinmaterial, based on the total weight of the coated proppant 100.

The layer 108 of the chemical treatment agent 102 can have any suitablethickness. The layer 108 can have thickness of at least about 0.1 nm, atleast about 0.5 nm, at least about 1 nm, at least about 2 nm, at leastabout 4 nm, at least about 8 nm, at least about 20 nm, at least about 60nm, at least about 100 nm, or at least about 200 nm. For example, thelayer 108 can have thickness from about 1 nm, about 5 nm, about 10 nm,about 25 nm, about 50 nm, about 100 nm, or about 150 nm to about 200 nm,about 300 nm, about 500 nm, or about 1,000 nm or more.

FIG. 2 is a cross sectional view of a coated proppant 200 containing thechemical treatment agent 102 dispersed within a coating 204 inaccordance with one or more embodiments. The chemical treatment agent102 can be homogenously or substantially homogeneously dispersedthroughout the coating 204. The coating 204 can contain the chemicaltreatment agent 102 in any suitable amounts. For example, the coating204 can have a chemical treatment agent 102 concentration of about atleast about 0.01 wt %, at least about 0.1 wt %, at least about 0.5 wt %,at least about 1 wt %, at least about 2 wt %, at least about 4 wt %, atleast about 6 wt %, or at least about 10 wt % based on the weight of thecoating 104. The coating 204 can include any suitable resin materialand/or epoxy resin material as disclosed herein. The coating 204 can bedegradable or non-degradable.

In one or more exemplary embodiments, the layer 108 of chemicaltreatment agent 102 can be formed between the coating 204 and theproppant particulate 106. For example, the layer 108 of chemicaltreatment agent 102 can surround and/or be deposited on an outer surface107 of the proppant particulate 106 in any suitable manner as disclosedin reference to FIG. 1 above. The coated proppant 200 can contain thechemical treatment agent 102 in any suitable amounts. According toseveral exemplary embodiments, the coated proppant 200 contains at leastabout 0.01 wt %, at least about 0.1 wt %, at least about 0.5 wt %, atleast about 1 wt %, at least about 2 wt %, at least about 4 wt %, atleast about 6 wt %, or at least about 10 wt % chemical treatment agent102 based on the total weight of the coated proppant 200. The coatedproppant 200 can contain the resin material in any suitable amounts.According to several exemplary embodiments, the coated proppant 200contains about 0.01 wt %, about 0.2 wt %, about 0.8 wt %, about 1.5 wt%, about 2.5 wt %, about 3.5 wt %, or about 5 wt % to about 8 wt %,about 15 wt %, about 30 wt %, about 50 wt %, or about 80 wt % resinmaterial, based on the total weight of the coated proppant 200.

FIG. 3 is a cross sectional view of an encapsulated proppant 300 havinga degradable, non-permeable shell 302 encapsulating a coated proppant,the coated proppant including the chemical treatment agent 102 infusedinto a porous proppant particulate 106 and surrounded by the resincoating 104. The resin coating 104 can be coated onto the porousproppant particulate 106. The degradable shell 302 can be directly orindirectly coated onto an outer surface 308 of the resin coating 104.The degradable shell 302 can coat or cover at least about 10%, at leastabout 30%, at least about 50%, at least about 70%, at least about 90%,at least about 95%, or at least about 99% of the entire outer surfacearea of the coated proppant. For example, the degradable shell 302 cancoat or cover about 100% of the entire outer surface area of the coatedproppant. The degradable shell 302 can coat or cover at least about 10%,at least about 30%, at least about 50%, at least about 70%, at leastabout 90%, at least about 95%, or at least about 99% of the entire outersurface 308 of the resin coating 104. For example, the coating can coator cover about 100% of the entire outer surface area of the coatedproppant such that the resin coating 104 is disposed between the porousproppant particulate 106 and the degradable shell 302.

The encapsulated proppant 300 can contain the chemical treatment agent102 in any suitable amounts. According to several exemplary embodiments,the encapsulated proppant 300 contains at least about 0.01 wt %, atleast about 0.1 wt %, at least about 0.5 wt %, at least about 1 wt %, atleast about 2 wt %, at least about 4 wt %, at least about 6 wt %, or atleast about 10 wt % chemical treatment agent 102 based on the totalweight of the encapsulated proppant 300. The encapsulated proppant 300can contain the resin coating 104 in any suitable amounts. According toseveral exemplary embodiments, the encapsulated proppant 300 containsabout 0.01 wt %, about 0.2 wt %, about 0.8 wt %, about 1.5 wt %, about2.5 wt %, about 3.5 wt %, or about 5 wt % to about 8 wt %, about 15 wt%, about 30 wt %, about 50 wt %, or about 80 wt % resin material, basedon the total weight of the encapsulated proppant 300.

The degradable shell 302 can also encapsulate any suitable configurationof proppant particulate. For example, FIG. 4 is a cross sectional viewof an encapsulated proppant 400 having the degradable, non-permeableshell 302 encapsulating an uncoated proppant 404, the uncoated proppant404 containing the chemical treatment agent 102 infused into a porousproppant particulate 106. The degradable shell 302 can be directly orindirectly coated onto an outer surface 107 of the porous proppantparticulate 106. The degradable shell 302 can coat or cover at leastabout 10%, at least about 30%, at least about 50%, at least about 70%,at least about 90%, at least about 95%, or at least about 99% of theentire outer surface area of the porous proppant particulate 106. Forexample, the degradable shell 302 can coat or cover about 100% of theentire outer surface area of the uncoated proppant 404. The encapsulatedproppant 400 can contain the chemical treatment agent 102 in anysuitable amounts. According to several exemplary embodiments, theencapsulated proppant 400 contains at least about 0.01 wt %, at leastabout 0.1 wt %, at least about 0.5 wt %, at least about 1 wt %, at leastabout 2 wt %, at least about 4 wt %, at least about 6 wt %, or at leastabout 10 wt % chemical treatment agent 102 based on the total weight ofthe encapsulated proppant 400.

FIG. 5 is a cross sectional view of an encapsulated proppant 500 havingthe degradable, non-permeable shell 302 encapsulating the coatedproppant 100 discussed above. For example, the degradable shell 302 canbe directly or indirectly coated onto an outer surface of the resincoating 104 of the coated proppant 100. The degradable shell 302 cancoat or cover at least about 10%, at least about 30%, at least about50%, at least about 70%, at least about 90%, at least about 95%, or atleast about 99% of the entire outer surface area of the resin coating104 of the coated proppant 100. For example, the degradable shell 302can coat or cover about 100% of the entire outer surface area of theresin coating 104. The degradable shell 302 can also cover, surround,and/or encapsulate the coated proppant 200.

According to several exemplary embodiments, the degradable shell 302 ispresent in the encapsulated proppant 300, 400, 500 in any suitableamount. According to several exemplary embodiments, the encapsulatedproppant 300, 400, 500 contains at least about 0.01 wt %, at least about0.1 wt %, at least about 0.5 wt %, at least about 1 wt %, at least about2 wt %, at least about 4 wt %, at least about 6 wt %, or at least about10 wt % degradable shell 302 based on the total weight of theencapsulated proppant 300, 400, 500. According to several exemplaryembodiments, the encapsulated proppant 300, 400, 500 contains about 0.01wt %, about 0.2 wt %, about 0.8 wt %, about 1.5 wt %, about 2.5 wt %,about 3.5 wt %, or about 5 wt % to about 8 wt %, about 15 wt %, about 30wt %, about 50 wt %, or about 80 wt % degradable shell 302, based on thetotal weight of the encapsulated proppant 300, 400, 500.

According to several exemplary embodiments, the chemical treatment agent102 is present in the encapsulated proppant 300, 400, 500 in anysuitable amount. According to several exemplary embodiments, theencapsulated proppant 300, 400, 500 contains at least about 0.01 wt %,at least about 0.1 wt %, at least about 0.5 wt %, at least about 1 wt %,at least about 2 wt %, at least about 4 wt %, at least about 6 wt %, orat least about 10 wt % chemical treatment agent 102 based on the totalweight of the encapsulated proppant 300, 400, 500. According to severalexemplary embodiments, the encapsulated proppant 300, 400, 500 containsabout 0.01 wt %, about 0.2 wt %, about 0.8 wt %, about 1.5 wt %, about2.5 wt %, or about 3.5 wt % to about 5 wt %, about 8 wt %, about 12 wt%, or about 20 wt % chemical treatment agent 102, based on the totalweight of the coated proppant 300, 400, 500.

The degradable shell 302 of the encapsulated proppant 300, 400, 500 canhave any suitable thickness. The degradable shell 302 can have thicknessof at least about 0.1 nm, at least about 0.5 nm, at least about 1 nm, atleast about 4 nm, at least about 8 nm, at least about 15 nm, at leastabout 30 nm, at least about 60 nm, at least about 100 nm, at least about200 nm, or at least about 500 nm. For example, the degradable shell 302can have thickness from about 1 nm, about 10 nm, about 20 nm, about 50nm, about 100 nm, about 150 nm, or about 200 nm to about 300 nm, about500 nm, about 750 nm, or about 1,000 nm or more.

In one or more exemplary embodiments, the proppant particulate 106 canbe or include natural sand. In one or more exemplary embodiments, theproppant particulate 106 can be or include ceramic proppant. The ceramicproppant can be or include porous ceramic proppant and non-porousceramic proppant.

The proppant particulates 106 can be or include silica and/or alumina inany suitable amounts. According to several exemplary embodiments, theproppant particulate 106 include less than 80 wt %, less than 60 wt %,less than 40 wt %, less than 30 wt %, less than 20 wt %, less than 10 wt%, or less than 5 wt % silica based on the total weight of the proppantparticulates 106, 206. According to several exemplary embodiments, theproppant particulate 106 include from about 0.1 wt % to about 70 wt %silica, from about 1 wt % to about 60 wt % silica, from about 2.5 wt %to about 50 wt % silica, from about 5 wt % to about 40 wt % silica, orfrom about 10 wt % to about 30 wt % silica. According to severalexemplary embodiments, the proppant particulate 106 include at leastabout 30 wt %, at least about 50 wt %, at least about 60 wt %, at leastabout 70 wt %, at least about 80 wt %, at least about 90 wt %, or atleast about 95 wt % alumina based on the total weight of the proppantparticulate 106. According to several exemplary embodiments, theproppant particulate includes from about 30 wt % to about 99.9 wt %alumina, from about 40 wt % to about 99 wt % alumina, from about 50 wt %to about 97 wt % alumina, from about 60 wt % to about 95 wt % alumina,or from about 70 wt % to about 90 wt % alumina.

According to several exemplary embodiments, the proppant compositionsdisclosed herein include proppant particulates 106 that aresubstantially round and spherical having a size in a range between about6 and 270 U.S. Mesh. For example, the size of the particulate 106 can beexpressed as a grain fineness number (GFN) in a range of from about 15to about 300, or from about 30 to about 110, or from about 40 to about70. According to such examples, a sample of sintered particles can bescreened in a laboratory for separation by size, for example,intermediate sizes between 20, 30, 40, 50, 70, 100, 140, 200, and 270U.S. mesh sizes to determine GFN. The correlation between sieve size andGFN can be determined according to Procedure 106-87-S of the AmericanFoundry Society Mold and Core Test Handbook, which is known to those ofordinary skill in the art.

The proppant compositions disclosed herein include proppant particulateshaving any suitable size. For example, the proppant particulate 106 canhave a mesh size of at least about 6 mesh, at least about 10 mesh, atleast about 16 mesh, at least about 20 mesh, at least about 25 mesh, atleast about 30 mesh, at least about 35 mesh, or at least about 40 mesh.According to several exemplary embodiments, the proppant particulate 106has a mesh size from about 6 mesh, about 10 mesh, about 16 mesh, orabout 20 mesh to about 25 mesh, about 30 mesh, about 35 mesh, about 40mesh, about 45 mesh, about 50 mesh, about 70 mesh, or about 100 mesh.According to several exemplary embodiments, the proppant particulate 106has a mesh size from about 4 mesh to about 120 mesh, from about 10 meshto about 60 mesh, from about 16 mesh to about 20 mesh, from about 20mesh to about 40 mesh, or from about 25 mesh to about 35 mesh.

According to several exemplary embodiments, the proppant compositionsdisclosed herein include porous and/or non-porous proppant particulateshaving any suitable permeability and conductivity in accordance with ISO13503-5: “Procedures for Measuring the Long-term Conductivity ofProppants,” and expressed in terms of Darcy units, or Darcies (D). Apack of the proppant particulate 106, having a 20/40 mesh size range,can have a long term permeability at 7,500 psi of at least about 1 D, atleast about 2 D, at least about 5 D, at least about 10 D, at least about20 D, at least about 40 D, at least about 80 D, at least about 120 D, atleast about 150 D, at least about 200 D, or at least about 250 D. Thepack of the proppant particulate 106, having a 20/40 mesh size range,can have a long term permeability at 12,000 psi of at least about 1 D,at least about 2 D, at least about 3 D, at least about 4 D, at leastabout 5 D, at least about 10 D, at least about 25 D, at least about 50D, at least about 100 D, at least about 150 D, or at least about 200 D.The pack of the proppant particulate 106, having a 20/40 mesh sizerange, can have a long term permeability at 15,000 psi of at least about1 D, at least about 2 D, at least about 3 D, at least about 4 D, atleast about 5 D, at least about 10 D, at least about 25 D, at leastabout 50 D, at least about 75 D, at least about 100 D, or at least about150 D. The pack of the proppant particulate 106, having a 20/40 meshsize range, can have a long term permeability at 20,000 psi of at leastabout 1 D, at least about 2 D, at least about 3 D, at least about 4 D,at least about 5 D, at least about 10 D, at least about 25 D, at leastabout 50 D, at least about 75 D, or at least about 100 D.

A pack of the proppant particulate 106 can have a long term conductivityat 7,500 psi of at least about 100 millidarcy-feet (mD-ft), at leastabout 200 mD-ft, at least about 300 mD-ft, at least about 500 mD-ft, atleast about 1,000 mD-ft, at least about 1,500 mD-ft, at least about2,000 mD-ft, or at least about 2,500 mD-ft. For example, a pack of theproppant particulate 106 can have a long term conductivity at 12,000 psiof at least about 50 mD-ft, at least about 100 mD-ft, at least about 200mD-ft, at least about 300 mD-ft, at least about 500 mD-ft, at leastabout 1,000 mD-ft, or at least about 1,500 mD-ft.

The proppant compositions disclosed herein include proppant particulates106 having any suitable shape. The proppant particulate 106 can besubstantially round, cylindrical, square, rectangular, elliptical, oval,egg-shaped, or pill-shaped. As shown, the proppant particulate 106 canbe substantially round and spherical. According to several exemplaryembodiments, the proppant particulates 106 of the proppant compositionsdisclosed herein have an apparent specific gravity of less than 3.1g/cm³, less than 3.0 g/cm³, less than 2.8 g/cm³, or less than 2.5 g/cm³.According to several exemplary embodiments, the proppant particulate 106has an apparent specific gravity of from about 3.1 to 3.4 g/cm³, fromabout 1.5 to about 2.2 g/cm³, from about 1.9 to about 2.5 g/cm³, or fromabout 2.6 to about 3.2 g/cm³. According to several exemplaryembodiments, the proppant particulate 106 has an apparent specificgravity of greater than 3.4 g/cm³, greater than 3.6 g/cm³, greater than4.0 g/cm³, or greater than 4.5 g/cm³.

The proppant particulate 106 can have any suitable specific gravity. Theproppant particulate 106 can have a specific gravity of at least about2.5, at least about 2.7, at least about 3, at least about 3.3, or atleast about 3.5. For example, the proppant particulate 106 can have aspecific gravity of about 2.5 to about 4.0, about 2.7 to about 3.8,about 3.5 to about 4.2, about 3.8 to about 4.4, or about 3.0 to about3.5. In one or more exemplary embodiments, the proppant particulate 106can have a specific gravity of less than 4 g/cc, less than 3.5 g/cc,less than 3 g/cc, less than 2.75 g/cc, less than 2.5 g/cc, less than2.25 g/cc, less than 2 g/cc, less than 1.75 g/cc, or less than 1.5 g/cc.For example, the proppant particulate 106 can have a specific gravity ofabout 1.3 g/cc to about 3.5 g/cc, about 1.5 g/cc to about 3.2 g/cc,about 1.7 g/cc to about 2.7 g/cc, about 1.8 g/cc to about 2.4 g/cc, orabout 2.0 g/cc to about 2.3 g/cc.

The proppant particulate 106 can have any suitable bulk density. In oneor more exemplary embodiments, the proppant particulate 106 have a bulkdensity of less than 3 g/cc, less than 2.5 g/cc, less than 2.2 g/cc,less than 2 g/cc, less than 1.8 g/cc, less than 1.6 g/cc, or less than1.5 g/cc. The proppant particulate 106 can have a bulk density of about1 g/cc, about 1.15 g/cc, about 1.25 g/cc, about 1.35 g/cc, or about 1.45g/cc to about 1.5 g/cc, about 1.6 g/cc, about 1.75 g/cc, about 1.9 g/cc,or about 2.1 g/cc or more. For example, the proppant particulate 106 canhave a bulk density of about 1.3 g/cc to about 1.8 g/cc, about 1.35 g/ccto about 1.65 g/cc, or about 1.5 g/cc to about 1.9 g/cc.

The proppant particulate 106 can have any suitable surface roughness.The proppant particulate 106 can have a surface roughness of less than 5μm, less than 4 μm, less than 3 μm, less than 2.5 μm, less than 2 μm,less than 1.5 μm, or less than 1 μm. For example, the proppantparticulate 106 can have a surface roughness of about 0.1 μm to about4.5 μm, about 0.4 μm to about 3.5 μm, or about 0.8 μm to about 2.8 μm.

The proppant particulate 106 can have any suitable pore sizedistribution. For example, the proppant particulate 106 can have astandard deviation in pore size of less than 6 μm, less than 4 μm, lessthan 3 μm, less than 2.5 μm, less than 2 μm, less than 1.5 μm, or lessthan 1 μm. The proppant particulate 106 can have any suitable averagemaximum or largest pore size. For example, the proppant particulate 106can have an average largest pore size of less than about 25 μm, lessthan about 20 μm, less than about 18 μm, less than about 16 μm, lessthan about 14 μm, or less than about 12 μm. The proppant particulate 106can have any suitable concentration of pores. For example, the proppantparticulate 106 can have less than 5,000, less than 4,500, less than4,000, less than 3,500, less than 3,000, less than 2,500, or less than2,200 visible pores at a magnification of 500× per square millimeter ofthe proppant particulate 106.

The proppant particulate 106 can have any suitable porosity. Accordingto several exemplary embodiments, the proppant particulate 106 can be orinclude porous ceramic proppant having any suitable porosity. The porousceramic proppant can have an internal interconnected porosity from about1%, about 2%, about 4%, about 6%, about 8%, about 10%, about 12%, orabout 14% to about 18%, about 20%, about 22%, about 24%, about 26%,about 28%, about 30%, about 34%, about 38%, about 45%, about 55%, about65%, or about 75% or more. In several exemplary embodiments, theinternal interconnected porosity of the porous ceramic proppant is fromabout 5% to about 75%, about 5% to about 15%, about 10% to about 30%,about 15% to about 35%, about 25% to about 45%, about 30% to about 55%,or about 35% to about 70%. According to several exemplary embodiments,the porous ceramic proppant can have any suitable average pore size. Forexample, the porous ceramic proppant can have an average pore size fromabout 2 nm, about 10 nm, about 15 nm, about 55 nm, about 110 nm, about520 nm, or about 1,100 to about 2,200 nm, about 5,500 nm, about 11,000nm, about 17,000 nm, or about 25,000 nm or more in its largestdimension. For example, the porous ceramic proppant can have an averagepore size can be from about 3 nm to about 30,000 nm, about 30 nm toabout 18,000 nm, about 200 nm to about 9,000, about 350 nm to about4,500 nm, or about 850 nm to about 1,800 nm in its largest dimension.

As discussed herein, the proppant particulates 106 can contain thechemical treatment agents 102 in any suitable manner. In one or moreexemplary embodiments, the proppant particulates 106 are infused with,coated with, and/or encapsulated with the one or more chemical treatmentagents 102. Suitable chemical treatment agents 102 can be or include anyone or more of tracers, scale inhibitors, hydrate inhibitors, hydrogensulfide scavenging materials, corrosion inhibitors, paraffin or waxinhibitors, including ethylene vinyl acetate copolymers, asphalteneinhibitors, organic deposition inhibitors, biocides, demulsifiers,defoamers, gel breakers, salt inhibitors, oxygen scavengers, ironsulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, nanoparticle dispersions, surfactants, combinations thereof,or any other oilfield chemical that can be helpful in the hydraulicfracturing process. In one or more exemplary embodiments, the scaleinhibitor can inhibit scales of calcium, barium, magnesium salts and thelike, including barium sulfate, calcium sulfate, and calcium carbonatescales. The composites can further have applicability in the treatmentof other inorganic scales, such as zinc sulfide, iron sulfide, etc. Inone or more exemplary embodiments, the scale inhibitors are anionicscale inhibitors. The scale inhibitors can include strong acids such asa phosphonic acid, phosphoric acid, phosphorous acid, phosphate esters,phosphonate/phosphonic acids, aminopoly carboxylic acids, chelatingagents, and polymeric inhibitors and salts thereof. The scale inhibitorscan also include organo phosphonates, organo phosphates and phosphateesters as well as the corresponding acids and salts thereof. The scaleinhibitors can also include polymeric scale inhibitors, such aspolyacrylamides, salts of acrylamido-methyl propane sulfonate/acrylicacid copolymer (AMPS/AA), phosphinated maleic copolymer (PHOS/MA) orsodium salt of polymaleic acid/acrylic acid/acrylamido-methyl propanesulfonate terpolymers (PMA/AMPS). In one or more exemplary embodiments,the scale inhibitors can include DTPA, (also known asdiethylenetriaminepentaacetic acid;diethylenetriamine-N,N,N′,N′,N″-pentaacetic acid; pentetic acid;N,N-Bis(2-(bis-(carboxymethyl)amino)ethyl)-glycine; diethylenetriaminepentaacetic acid,[[(Carboxymethyl)imino]bis(ethylenenitrilo)]-tetra-acetic acid); EDTA:(also known as edetic acid; ethylenedinitrilotetraacetic acid; EDTA freebase; EDTA free acid; ethylenediamine-N,N,N′,N′-tetraacetic acid;hampene; Versene; N,N′-1,2-ethane diylbis-(N-(carboxymethyl)glycine);ethylenediamine tetra-acetic acid); NTA, (also known asN,N-bis(carboxymethyl)glycine; triglycollamic acid; trilone A;alpha,alpha′,alpha″-trimethylaminetricarboxylic acid;tri(carboxymethyl)amine; aminotriacetic acid; Hampshire NTA acid;nitrilo-2,2′,2″-triacetic acid; titriplex i; nitrilotriacetic acid);APCA (aminopolycarboxylic acids); phosphonic acids; EDTMP(ethylenediaminetetramethylene-phosphonic acid); DTPMP (diethylenetriaminepentamethylenephosphonic acid); NTMP(nitrilotrimethylenephosphonic acid); polycarboxylic acids, gluconates,citrates, polyacrylates, and polyaspartates or any combination thereof.The scale inhibitors can also include any of the ACCENT™ scaleinhibitors, commercially available from The Dow Chemical Company. Thescale inhibitors can also include potassium salts of maleic acidcopolymers. In one or more exemplary embodiments, the chemical treatmentagent 102 is DTPMP.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any one or more salt inhibitors. In one or moreexemplary embodiments, the salt inhibitor can include any suitable saltinhibitor, including, but not limited to Na-Minus®, Na-Minus®-55, andWFT 9725, each commercially available from Weatherford InternationalLtd., Desalt Liquid salt inhibitor commercially available from JACAMChemicals, LLC, and potassium ferricyanide and any combination thereof.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any one or more demulsifying agents. The demulsifyingagents can include, but are not limited to, condensation polymers ofalkylene oxides and glycols, such as ethylene oxide and propylene oxidecondensation polymers of di-propylene glycol as well as trimethylolpropane; and alkyl substituted phenol formaldehyde resins, bis-phenyldiepoxides, and esters and diesters of same. The demulsifying agents canalso include oxyalkylated phenol formaldehyde resins, oxyalkylatedamines and polyamines, di-epoxidized oxyalkylated polyethers, polytriethanolamine methyl chloride quaternary, melamine acid colloid, andaminomethylated polyacrylamide.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any one or more corrosion inhibitors. Suitablecorrosion inhibitors can include, but are not limited to, fattyimidazolines, alkyl pyridines, alkyl pyridine quaternaries, fatty aminequaternaries and phosphate salts of fatty imidazolines. In one or moreexemplary embodiments, the chemical treatment agent 102 can be orinclude any one or more suitable foaming agents. Suitable foaming agentscan include, but are not limited to, oxyalkylated sulfates orethoxylated alcohol sulfates, or mixtures thereof. In one or moreexemplary embodiments, the chemical treatment agent 102 can be orinclude any one or more suitable oxygen scavengers. Suitable oxygenscavengers can include triazines, maleimides, formaldehydes, amines,carboxamides, alkylcarboxyl-azo compounds cumine-peroxide compoundsmorpholino and amino derivatives morpholine and piperazine derivatives,amine oxides, alkanolamines, aliphatic and aromatic polyamines.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any one or more paraffin inhibitors. Suitable paraffininhibitors can include, but are not limited to, ethylene/vinyl acetatecopolymers, acrylates (such as polyacrylate esters and methacrylateesters of fatty alcohols), and olefin/maleic esters. In one or moreexemplary embodiments, the chemical treatment agent 102 can be orinclude any one or more asphaltene inhibitors. Suitable asphalteneinhibitors can include, but are not limited to, asphaltene treatingchemicals include but are not limited to fatty ester homopolymers andcopolymers (such as fatty esters of acrylic and methacrylic acidpolymers and copolymers) and sorbitan monooleate.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include a thermal neutron absorbing material. In one or moreexemplary embodiments, the thermal neutron absorbing material is boron,cadmium, gadolinium, iridium, samarium, or mixtures thereof. The thermalneutron absorbing material can leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, and leak from any of the proppant 100,200, 300, 400, 500 and into a fracture, a formation, and/or a wellbore.A downhole tool emitting thermal neutrons can detect the presence of thethermal neutron absorbing material to detect proppant placement,producing and non-producing zones, and fracture size, shape, andlocation.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any suitable radioactive material. In one or moreexemplary embodiments, the radioactive material can include radioactiveisotopes, or gamma-ray emitting isotopes, of gold, iodine, iridium,scandium, antimony, silver, hafnium, zirconium, rubidium, chromium,iron, strontium, cobalt, zinc, or mixtures thereof. The radioactivematerial can leach, elute, diffuse, bleed, discharge, desorb, dissolve,drain, seep, and leak from any of the proppant 100, 200, 300, 400, 500and into a fracture, a formation, and/or a wellbore. A downhole tool candetect the presence of the radioactive material to detect proppantplacement, producing and non-producing zones, and fracture size, shape,and location.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any one or more suitable surfactants. The one or moresuitable surfactants can be selected based on the necessary adjustmentin wetting characteristics of the proppant for the desired productionenhancement. For example, suitable surfactants can be found in U.S.Patent Application Publication No. 2005/0244641, incorporated byreference herein in its entirety. The surfactants can also be selectedfrom any number of surfactants known to those of ordinary skill in theart, including, for example, anionic, cationic, nonionic, and amphotericsurfactants, or combinations thereof. According to several exemplaryembodiments, suitable surfactants include but are not limited tosaturated or unsaturated long-chain fatty acids or acid salts,long-chain alcohols, polyalcohols, dimethylpolysiloxane andpolyethylhydrosiloxane. According to several exemplary embodiments,suitable surfactants include but are not limited to linear and branchedcarboxylic acids and acid salts having from about 4 to about 30 carbonatoms, linear and branched alkyl sulfonic acids and acid salts havingfrom about 4 to about 30 carbon atoms, linear alkyl benzene sulfonatewherein the linear alkyl chain includes from about 4 to about 30 carbonatoms, sulfosuccinates, phosphates, phosphonates, phospholipids,ethoxylated compounds, carboxylates, sulfonates and sulfates, polyglycolethers, amines, salts of acrylic acid, pyrophosphate and mixturesthereof. Cationic surfactants can include those containing a quaternaryammonium moiety (such as a linear quaternary amine, a benzyl quaternaryamine or a quaternary ammonium halide), a quaternary sulfonium moiety ora quaternary phosphonium moiety or mixtures thereof. Suitablesurfactants containing a quaternary group can include quaternaryammonium halide or quaternary amine, such as quaternary ammoniumchloride or a quaternary ammonium bromide. Amphoteric surfactants caninclude glycinates, amphoacetates, propionates, betaines and mixturesthereof. Anionic surfactants can include sulfonates (like sodium xylenesulfonate and sodium naphthalene sulfonate), phosphonates,ethoxysulfates and mixtures thereof. According to several exemplaryembodiments, suitable surfactants include but are not limited to sodiumstearate, octadecanoic acid, hexadecyl sulfonate, lauryl sulfate, sodiumoleate, ethoxylated nonyl phenol, sodium dodecyl sulfate, sodiumdodecylbenzene sulfonate, laurylamine hydrochloride, trimethyldodecylammonium chloride, cetyl trimethyl ammonium chloride,polyoxyethylene alcohol, alkylphenolethoxylate, Polysorbate 80,propylene oxide modified polydimethylsiloxane, dodecyl betaine,lauramidopropyl betaine, cocamido-2-hydroxy-propyl sulfobetaine, alkylaryl sulfonate, fluorosurfactants and perfluoropolymers and terpolymers,castor bean adducts and combinations thereof. According to severalexemplary embodiments, the surfactant is sodium dodecylbenzene sulfonateor sodium dodecyl sulfate. According to several exemplary embodiments,the surfactants are used at a concentration below the critical micelleconcentration (CMC) in aqueous and hydrocarbon carrier fluids. Further,surfactants as production enhancement additives are commerciallyavailable from CESI Chemical, Inc., as SG-400N, SG-401N, and LST-36.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any suitable nanoparticle dispersion. The nanoparticledispersion can be coated on and/or infused in the proppant particulate106 so that the proppant particulate 106 can act as a carrier for thenanoparticle dispersion in a hydraulic fracturing operation. Theinclusion of the nanoparticle dispersion into and/or underneath thecoating 104, 204 of a coated proppant or into the internal porosity ofporous ceramic proppant, rather than simply injecting or pumping thenanoparticle dispersion into a well formation in fluid form, improvesnot only the wetting characteristics of the formation surfaces but alsoof the proppant itself. The nanoparticle dispersion interacts with thesurface of the proppant to alter its wetting characteristics. Further,as fluids flow through the proppant pack in the formation, some of thenanoparticle dispersion may be released into the fracture and adhere toand improve the wettability, or fluid affinity, of the formationsurfaces. Thus, the use of nanoparticle dispersions that are coated onand/or infused into proppant offers benefits similar to those obtainedby pumping the nanoparticle dispersion into the formation in fluid form,but the increased interaction of the nanoparticle dispersion with theproppant offers the additional benefit of improved wettability of theproppant.

The nanoparticle dispersions can include a number of differentnanoparticle materials known to those of ordinary skill in the art,including polymers, silica, metals, metal oxides, and other inorganicmaterials, that are suspended in an aqueous or non-aqueous solventfluid. According to several exemplary embodiments, suitable materialsinclude but are not limited to nanoparticles such as silicon dioxide,zirconium dioxide, antimony dioxide, zinc oxide, titanium dioxide,aluminum dioxide, particles derived from natural minerals, syntheticparticles, and combinations thereof. According to several exemplaryembodiments, one or more of silicon dioxide, zirconium dioxide andantimony dioxide are added at about 65 nanometers or less in diameter(in several exemplary embodiments 1-10 nm) and have a polydispersity ofless than about 20%.

The selection of a specific nanoparticle dispersion or surfactant to becoated on and/or infused into the proppant particulate 106 depends onthe necessary adjustment in wetting characteristics of the proppant forthe desired production enhancement. Suitable nanoparticle dispersions orsurfactants may be selected from any number of commercially availableproducts. For example, nanoparticle dispersion products are commerciallyavailable from FTS International® as NPD 2000® and NPD 3000®.Nanoparticle dispersions are also commercially available from CESIChemical, Inc., a subsidiary of Flotek Industries, Inc., as MA-844W,MA-845, StimOil® FBA M, StimOil® FBA Plus, and StimOil® FBA Plus Enviro.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any one or more suitable gel breakers. Suitable gelbreakers can be or include oxidizers such as bleach, hypochlorites,percarbonates, perborates, permanganates, peroxides, and halogens. Inone or more exemplary embodiments, the chemical treatment agent 102 canbe or include any one or more suitable biocides. Suitable biocides canbe or include bronopol, dazomet, glutaraldehyde, quartenary ammoniumsalts, and bleach.

In one or more exemplary embodiments, the chemical treatment agent 102can be or include any suitable tracer, such as one or more metallic ornon-metallic elements, one or more nanoparticles, and/or one or morebiological markers. According to several exemplary embodiments, thebiological marker is DNA. DNA, or deoxyribose nucleic acid, is sometimesa double-stranded helical molecule that encodes the genetic informationof almost all living systems. Each DNA molecule can be unique as aresult of a particular sequence of nitrogenous bases—adenine (“A”),thymine (“T”), cytosine (“C”) and guanine (“G”)—contained with themolecule. The double helix structure is formed and maintained by thepairing of a nitrogenous base on one phosphate/sugar backbone carrierchain with a nitrogenous base on the other phosphate/sugar backbonecarrier chain through hydrogen bonding. Specifically, an adenine basewill pair with a thymine base (an “AT” base pair), and a cytosine basewill pair with a guanine base (a “GC” base pair). Probability terms canbe calculated for the frequency of a given sequence of bases, and aslong as a large enough DNA molecule is used, the “uniqueness” of aparticular molecule of DNA can be known with sufficient certainty. TheDNA molecule may be naturally occurring or a manufactured (synthetic)DNA and can be double stranded or single stranded. Synthetic DNA iscommercially available and may be manufactured to order by severalspecialized DNA manufacturers, such as GenScript, Synthetic Genomics,DNA 2.0, Genewiz, Inc., Life Technologies, and Cambrian Genomics.Further, the DNA can be “encapsulated” to enhance its survivability atdownhole reservoir conditions and to otherwise alter its interactionwith formation fluids. Additionally, specific DNA sequences may beselected for use based on compatibility with the thermal environment ofa specific well.

DNA alone can be used as the biological marker. DNA is typicallywater-soluble and can be infused into, coated onto, and/or mixed withthe coating 104, 204 on the proppant particulate 106 without anymodification in order to function as a water-soluble biological marker.According to several exemplary embodiments, the DNA can be formulated insuch a way that it is hydrocarbon-soluble and will separate intohydrocarbon fluids as well. For example, the water-solubility of DNA isdue to the negative charges associated with the phosphodiester groups ofthe DNA. The negative charges of the phosphodiester structures can beremoved by methylation. Methylation of this region of the DNA moleculewill ensure that this part of the molecule becomes hydrophobic, i.e.,hydrocarbon-soluble, thereby ensuring that the DNA molecule is solublein the hydrocarbon phase. Other procedures for formulatinghydrocarbon-soluble DNA can be found in U.S. Pat. No. 5,665,538, theentire disclosure of which is herein incorporated by reference.

While DNA itself can be used as a biological marker, the reservoirconditions in which the DNA is placed may not be optimal for the longterm survivability of the DNA. These conditions include reservoirtemperatures exceeding 200° F. and sometimes up to 400° F., as well ashighly saline formation waters. However, numerous DNA encapsulationtechniques are well known to those of ordinary skill in the art and byencapsulating the DNA, its survivability in harsh conditions is greatlyenhanced. The partitioning of the DNA, whether into the hydrocarbon orwater phase, can be tailored by tailoring the encapsulation material. Inparticular, the wettability or fluid affinity of the encapsulationmaterial can be tailored to favor water or hydrocarbons.

Additionally, molecules containing specific nucleotide sequences can beselectively used to enhance compatibility with the harsh wellbore andformation temperatures and pressures based on the improved thermalstability displayed by DNA molecules having higher concentrations ofcertain base pairs. Specifically, the DNA molecules having the greatestthermal resistance are those which include higher levels of GC basepairs and lower levels of AT base pairs. For example, the sequence GCAT(with corresponding base pair sequence CGTA) shows thermal stability attemperatures of from about 186 to 221° F. The sequence GCGC (withcorresponding base pair sequence CGCG) is thermally resistant attemperatures of up to about 269 to 292° F. Conversely, the inclusion ofhigher levels of AT base pairs reduces thermal stability. For example,some thymine in the combination reduces the stability such that thesequence ATCG (with corresponding base pair sequence TAGC) only survivesat temperatures of up to about 222 to 250° F., while the sequence TATA(with corresponding base pair sequence ATAT) is thermally stable attemperatures of up to only about 129 to 175° F. In addition, if the DNAmolecules that include the sequence ATCG (with corresponding base pairsequence TAGC) are manipulated to include a modification known asG-clamp, the thermal stability increases by an additional 32° F. or fromtemperatures of up to about 254 to 282° F. As shown below, the G-clampmodification involves adding a tricyclic analogue of cytosine giving theduplex base pair (G-C) an additional hydrogen bond.

By increasing the hydrogen bonding of the duplex base pair from 3 to 4,the thermal stability increases by an additional 32° F.

The DNA can be either single stranded or double stranded. The naturalorientation of DNA in the double stranded version is the Watson-Crickpairing. Synthetic DNA, however, is not constrained in the same way asnatural DNA. Still, the indicator of thermal stability is athermodynamic reorientation of the strands and consists primarily of thestrands separating into two single strands. This is known as melting andhappens over a narrow temperature range. What has been observed is thatthe DNA of some organisms resists this thermal collapse, examples beingcertain thermophilic organisms. Analysis of their genomes gives a directcorrelation between the levels of G-C DNA in the sequences. Thermalstability is directly or indirectly related to the number of hydrogenbonds between the bases in the duplex pairs. However, the stacking(pairing in the double strands) is also a factor. It has been determinedthat an important feature of thermal stability in natural DNA reliesheavily upon the molar ratio of G-C pairing since this gives the highestdensity of hydrogen bonds. Thermal stability ultimately depends upon theso-called melting point where the strands of a double stranded DNAseparate. This has no significance to single stranded synthetic DNA,however, which is already separated. The separation of the strands ofdouble stranded DNA which occurs at the melting point is to some extentreversible. The strands can re-join once the temperature dropssufficiently. The thermal stability depends upon the thermal resistanceof the base pairs or duplex units as well as the stacking forces whichjoin the strands of double stranded DNA. As noted above, thermalstability can also be improved by modifying the molecular arrangementwithin a particular base pair. For instance, in addition to theG-G-Clamp modification noted above, the thermal stability of an A-T basepair can be improved, as shown below, by modifying the adenine-thyminebase pair to include a 2-aminoadenine-T complex which increases thehydrogen bonding in the complex from 2 to 3 and increases its thermalstability by about 5° F.

The thermal stability of specific base pairs can be used to generate athermodynamic assessment of potential. As noted above, reasonablechemical modifications can extend this thermal range and retain theessential features of DNA for the purposes of measurement. The chemicalnature of DNA means that it is susceptible to hydrolysis and the rate ofhydrolysis increases with increasing temperature. Hydrolysis is anotherroute for the decomposition of DNA in addition to decomposition due toits melting behavior as discussed above. That said, it is known that anumber of organisms survive extremes of temperature which means thattheir genetic material must have some inherent thermal stability. Thisresponse has been directly correlated to the molar fraction of G-C basepairs irrespective of whether such base pairs are present as single ordouble strands. Natural DNA, however, is chromosomal and so must bedouble stranded.

Also it has been shown that the repetition of the G-C duplex appears toimpart more stability since it has a direct effect upon the thermalresistance of the DNA. This shows how various organisms cope with hightemperature by incorporating a larger G-C molar fraction into theirgenome. It appears that the molar fraction of G-C is the key rather thanany weak link, which might be incorporated into the sequence. Chainterminators appear to have little overall effect on the thermalstability of the DNA. Essentially, what this means is that the molarfraction of certain base pairs in the DNA sequence can be variedaccording to the temperature range required. Getting down to the detailof destruction reactions for the DNA sequence will depend upon theenvironment to which a particular DNA sequence will be subjected and theexposure to hydrolysis reactions are an area of concern. However themodifications of the base pairs discussed above which can be introducedwhile still retaining the inherent features which make DNA an idealtracer offer clear routes for tailor-made tracers for oilfield use.

Selectively using a specific DNA molecule as a biological marker basedon its thermal stability properties allows for the use of DNA as abiological marker over a far wider range of conditions than is currentlypossible. Further, the survival of the DNA molecules at highertemperatures allows for accurate detection even with very low levels ofDNA present in the formation by avoiding degradation of the DNA.Additionally, the diverse number of unique DNA molecules vastly adds tothe number of unique tracers which can be applied in the oilfield,thereby greatly increasing both the range and diversity of oilfieldoperations to which biological markers can be applied and greatlyimproving the knowledge and understanding of increasingly complex wellsand their behavior. This knowledge will lead to better completion andstimulation practices resulting in cost savings and improved wellperformance.

In several exemplary embodiments, a DNA molecule exhibiting specificthermostability properties, based on its specific nitrogenous basecomposition that are compatible with the thermal environment of aspecific well, can be selectively infused into and/or coated onto theproppant particulate 106 to be used in the well operations according tothe methods and embodiments described herein. For example, for wellsexhibiting temperatures of up to about 269 to 292° F., a DNA moleculecontaining the GCGC sequence could be synthesized and infused intoand/or coated onto the proppant particulates 106 to be injected into thewell formation. This DNA molecule would better withstand the thermalconditions of the well, thereby allowing it to be more effectively usedas a biological marker that conveys information regarding well formationand production.

According to several exemplary embodiments, the chemical treatment agent102, such as a biological marker separates from the proppantparticulates 106 continuously over a period of up to about one year, upto about five years, or up to about ten years after placement of theproppant in the hydraulically created fracture. Systems, techniques andcompositions for providing for the sustained release of DNA are wellknown to those of ordinary skill in the art. For example, EuropeanPatent No. 1,510,224, the entire disclosure of which is incorporatedherein by reference, discloses several methods for enabling thesustained release of DNA over a period of time. According to severalexemplary embodiments, DNA is encapsulated with a polymer or a materialinfused with DNA is coated with a permeable nondegradeable coating. Inseveral exemplary embodiments, the encapsulating polymer includes one ormore of high melting acrylate-, methacrylate- or styrene-based polymers,block copolymers of polylactic-polyglycolic acid, polyglycolics,polylactides, polylactic acid, gelatin, water-soluble polymers,cross-linkable water-soluble polymers, lipids, gels, silicas, or othersuitable encapsulating materials. Additionally, the encapsulatingpolymer may include an encapsulating material that includes a linearpolymer containing degradable co-monomers or a cross-linked polymercontaining degradable cross-linkers.

In one or more exemplary embodiments, the internal interconnectedporosity of the porous ceramic proppant can be infused with a chemicaltreatment agent 102 such as a biological marker so that the porousceramic proppant acts as a carrier for the biological marker in ahydraulic fracturing operation. According to several exemplaryembodiments, the biological marker is DNA. DNA, or deoxyribose nucleicacid, is sometimes a double-stranded helical molecule that encodes thegenetic information of almost all living systems. Each DNA molecule canbe unique as a result of a particular sequence of nitrogenousbases—adenine (“A”), thymine (“T”), cytosine (“C”) and guanine(“G”)—contained with the molecule. The double helix structure is formedand maintained by the pairing of a nitrogenous base on onephosphate/sugar backbone carrier chain with a nitrogenous base on theother phosphate/sugar backbone carrier chain through hydrogen bonding.Specifically, an adenine base will pair with a thymine base (an “AT”base pair), and a cytosine base will pair with a guanine base (a “GC”base pair). Probability terms can be calculated for the frequency of agiven sequence of bases, and as long as a large enough DNA molecule isused, the “uniqueness” of a particular molecule of DNA can be known withsufficient certainty. The DNA molecule may be naturally occurring or amanufactured (synthetic) DNA and can be double stranded or singlestranded. Synthetic DNA is commercially available and may bemanufactured to order by several specialized DNA manufacturers, such asGenScript, Synthetic Genomics, DNA 2.0, Genewiz, Inc., LifeTechnologies, and Cambrian Genomics. Further, the DNA can be“encapsulated” to enhance its survivability at downhole reservoirconditions and to otherwise alter its interaction with formation fluids.Additionally, specific DNA sequences may be selected for use based oncompatibility with the thermal environment of a specific well.

According to several exemplary embodiments, the coating 104, 204 can beor include a resin material and/or an epoxy resin material. The coating104, 204 can include any suitable resin material and/or epoxy resinmaterial. According to several exemplary embodiments, the resin materialincludes any suitable resin. For example, the resin material can includea phenolic resin, such as a phenol-formaldehyde resin. According toseveral exemplary embodiments, the phenol-formaldehyde resin has a molarratio of formaldehyde to phenol (F:P) from a low of about 0.6:1, about0.9:1, or about 1.2:1 to a high of about 1.9:1, about 2.1:1, about2.3:1, or about 2.8:1. For example, the phenol-formaldehyde resin canhave a molar ratio of formaldehyde to phenol of about 0.7:1 to about2.7:1, about 0.8:1 to about 2.5:1, about 1:1 to about 2.4:1, about 1.1:1to about 2.6:1, or about 1.3:1 to about 2:1. The phenol-formaldehyderesin can also have a molar ratio of formaldehyde to phenol of about0.8:1 to about 0.9:1, about 0.9:1 to about 1:1, about 1:1 to about1.1:1, about 1.1:1 to about 1.2:1, about 1.2:1 to about 1.3:1, or about1.3:1 to about 1.4:1.

According to several exemplary embodiments, the phenol-formaldehyderesin has a molar ratio of less than 1:1, less than 0.9:1, less than0.8:1, less than 0.7:1, less than 0.6:1, or less than 0.5:1. Forexample, the phenol-formaldehyde resin can be or include a phenolicnovolac resin. Phenolic novolac resins are well known to those ofordinary skill in the art, for instance see U.S. Pat. No. 2,675,335 toRankin, U.S. Pat. No. 4,179,429 to Hanauye, U.S. Pat. No. 5,218,038 toJohnson, and U.S. Pat. No. 8,399,597 to Pullichola, the entiredisclosures of which are incorporated herein by reference. Suitableexamples of commercially available novolac resins include novolac resinsavailable from Plenco™, Durite® resins available from Momentive, andnovolac resins available from S.I. Group.

According to several exemplary embodiments, the phenol-formaldehyderesin has a weight average molecular weight from a low of about 200,about 300, or about 400 to a high of about 1,000, about 2,000, or about6,000. For example, the phenol-formaldehyde resin can have a weightaverage molecular weight from about 250 to about 450, about 450 to about550, about 550 to about 950, about 950 to about 1,500, about 1,500 toabout 3,500, or about 3,500 to about 6,000. The phenol-formaldehyderesin can also have a weight average molecular weight of about 175 toabout 800, about 700 to about 3,330, about 1,100 to about 4,200, about230 to about 550, about 425 to about 875, or about 2,750 to about 4,500.

According to several exemplary embodiments, the phenol-formaldehyderesin has a number average molecular weight from a low of about 200,about 300, or about 400 to a high of about 1,000, about 2,000, or about6,000. For example, the phenol-formaldehyde resin can have a numberaverage molecular weight from about 250 to about 450, about 450 to about550, about 550 to about 950, about 950 to about 1,500, about 1,500 toabout 3,500, or about 3,500 to about 6,000. The phenol-formaldehyderesin can also have a number average molecular weight of about 175 toabout 800, about 700 to about 3,000, about 1,100 to about 2,200, about230 to about 550, about 425 to about 875, or about 2,000 to about 2,750.

According to several exemplary embodiments, the phenol-formaldehyderesin has a z-average molecular weight from a low of about 200, about300, or about 400 to a high of about 1,000, about 2,000, or about 9,000.For example, the phenol-formaldehyde resin can have a z-averagemolecular weight from about 250 to about 450, about 450 to about 550,about 550 to about 950, about 950 to about 1,500, about 1,500 to about3,500, about 3,500 to about 6,500, or about 6,500 to about 9,000. Thephenol-formaldehyde resin can also have a z-average molecular weight ofabout 175 to about 800, about 700 to about 3,330, about 1,100 to about4,200, about 230 to about 550, about 425 to about 875, or about 4,750 toabout 8,500.

According to several exemplary embodiments, the phenol-formaldehyderesin has any suitable viscosity. The phenol-formaldehyde resin can be asolid or liquid at 25° C. For example, the viscosity of thephenol-formaldehyde resin can be from about 1 centipoise (cP), about 100cP, about 250 cP, about 500 cP, or about 700 cP to about 1,000 cP, about1,250 cP, about 1,500 cP, about 2,000 cP, or about 2,200 cP at atemperature of about 25° C. In another example, the phenol-formaldehyderesin can have a viscosity from about 1 cP to about 125 cP, about 125 cPto about 275 cP, about 275 cP to about 525 cP, about 525 cP to about 725cP, about 725 cP to about 1,100 cP, about 1,100 cP to about 1,600 cP,about 1,600 cP to about 1,900 cP, or about 1,900 cP to about 2,200 cP ata temperature of about 25° C. In another example, thephenol-formaldehyde resin can have a viscosity from about 1 cP to about45 cP, about 45 cP to about 125, about 125 cP to about 550 cP, about 550cP to about 825 cP, about 825 cP to about 1,100 cP, about 1,100 cP toabout 1,600 cP, or about 1,600 cP to about 2,200 cP at a temperature ofabout 25° C. The viscosity of the phenol-formaldehyde resin can also befrom about 500 cP, about 1,000 cP, about 2,500 cP, about 5,000 cP, orabout 7,500 cP to about 10,000 cP, about 15,000 cP, about 20,000 cP,about 30,000 cP, or about 75,000 cP at a temperature of about 150° C.For example, the phenol-formaldehyde resin can have a viscosity fromabout 750 cP to about 60,000 cP, about 1,000 cP to about 35,000 cP,about 4,000 cP to about 25,000 cP, about 8,000 cP to about 16,000 cP, orabout 10,000 cP to about 12,000 cP at a temperature of about 150° C. Theviscosity of the phenol-formaldehyde resin can be determined using aBrookfield viscometer.

According to several exemplary embodiments, the phenol-formaldehyderesin can have pH from a low of about 1, about 2, about 3, about 4,about 5, about 6, about 7 to a high of about 8, about 9, about 10, about11, about 12, or about 13. For example, the phenol-formaldehyde resincan have a pH from about 1 to about 2.5, about 2.5 to about 3.5, about3.5 to about 4.5, about 4.5 to about 5.5, about 5.5 to about 6.5, about6.5 to about 7.5, about 7.5 to about 8.5, about 8.5 to about 9.5, about9.5 to about 10.5, about 10.5 to about 11.5, about 11.5 to about 12.5,or about 12.5 to about 13.

According to several exemplary embodiments of the present invention, thecoating 104, 204 applied to the proppant particulates 106 is an epoxyresin. According to such embodiments, the coating 104, 204 can be orinclude any suitable epoxy resin. For example, the epoxy resin caninclude bisphenol A, bisphenol F, aliphatic, or glycidylamine epoxyresins, and any mixtures or combinations thereof. An example of acommercially available epoxy resin is BE188 Epoxy Resin, available fromChang Chun Plastics Co., Ltd.

According to several exemplary embodiments, the epoxy resin can have anysuitable viscosity. The epoxy resin can be a solid or liquid at 25° C.For example, the viscosity of the epoxy resin can be from about 1 cP,about 100 cP, about 250 cP, about 500 cP, or about 700 cP to about 1,000cP, about 1,250 cP, about 1,500 cP, about 2,000 cP, or about 2,200 cP ata temperature of about 25° C. In another example, the epoxy resin canhave a viscosity from about 1 cP to about 125 cP, about 125 cP to about275 cP, about 275 cP to about 525 cP, about 525 cP to about 725 cP,about 725 cP to about 1,100 cP, about 1,100 cP to about 1,600 cP, about1,600 cP to about 1,900 cP, or about 1,900 cP to about 2,200 cP at atemperature of about 25° C. In another example, the epoxy resin can havea viscosity from about 1 cP to about 45 cP, about 45 cP to about 125 cP,about 125 cP to about 550 cP, about 550 cP to about 825 cP, about 825 cPto about 1,100 cP, about 1,100 cP to about 1,600 cP, or about 1,600 cPto about 2,200 cP at a temperature of about 25° C. The viscosity of theepoxy resin can also be from about 500 cP, about 1,000 cP, about 2,500cP, about 5,000 cP, or about 7,000 cP to about 10,000 cP, about 12,500cP, about 15,000 cP, about 17,000 cP, or about 20,000 cP at atemperature of about 25° C. In another example, the epoxy resin can havea viscosity from about 1,000 cP to about 12,000 cP, about 2,000 cP toabout 11,000 cP, about 4,000 cP to about 10,500 cP, or about 7,500 cP toabout 9,500 cP at a temperature of about 25° C. The viscosity of theepoxy resin can also be from about 500 cP, about 1,000 cP, about 2,500cP, about 5,000 cP, or about 7,500 cP to about 10,000 cP, about 15,000cP, about 20,000 cP, about 30,000 cP, or about 75,000 cP at atemperature of about 150° C. For example, the epoxy resin can have aviscosity from about 750 cP to about 60,000 cP, about 1,000 cP to about35,000 cP, about 4,000 cP to about 25,000 cP, about 8,000 cP to about16,000 cP, or about 10,000 cP to about 12,000 cP at a temperature ofabout 150° C.

According to several exemplary embodiments, the epoxy resin can have pHfrom a low of about 1, about 2, about 3, about 4, about 5, about 6,about 7 to a high of about 8, about 9, about 10, about 11, about 12, orabout 13. For example, the epoxy resin can have a pH from about 1 toabout 2.5, about 2.5 to about 3.5, about 3.5 to about 4.5, about 4.5 toabout 5.5, about 5.5 to about 6.5, about 6.5 to about 7.5, about 7.5 toabout 8.5, about 8.5 to about 9.5, about 9.5 to about 10.5, about 10.5to about 11.5, about 11.5 to about 12.5, or about 12.5 to about 13.

Methods for coating proppant particulates with resins and/or epoxyresins are well known to those of ordinary skill in the art, forinstance see U.S. Pat. No. 2,378,817 to Wrightsman, U.S. Pat. No.4,873,145 to Okada and U.S. Pat. No. 4,888,240 to Graham, the entiredisclosures of which are incorporated herein by reference.

According to one or more exemplary embodiments, the chemical treatmentagent 102 is mixed with or otherwise added to the resin coating 104, 204prior to coating the proppant particulates 106 with the resin coating104, 204. For example, the chemical treatment agent 102 can behomogenously mixed with the coating 104, 204 prior to coating theproppant particulates 106 with the coating 104, 204.

According to one or more exemplary embodiments, the proppantparticulates 106 are porous ceramic particulates infused with one ormore chemical treatment agents 102. Methods for infusing porous ceramicparticulates with chemical treatment agents are well known to those ofordinary skill in the art, such as those disclosed in U.S. Pat. No.5,964,291 and U.S. Pat. No. 7,598,209, the entire disclosures of whichare incorporated herein by reference. According to several exemplaryembodiments, the porous ceramic particulates 106 act as a carrier forthe chemical treatment agent 102 in a hydraulic fracturing operation.

According to several exemplary embodiments, the coating 104, 204 can beor include a degradable coating. Specifically, as the coating degrades,the chemical treatment agent 102 mixed with the coating 104, 204,disposed between the coating 104, 204 and the proppant particulate 106,and/or infused in the proppant particulate 106 can be released into thefracture. The amount and molecular weight of the degradable coating 104,204 can be varied to provide for longer or shorter degrade times andtailored release of the chemical treatment agent 102.

According to certain embodiments, the degradable coating 104, 204 caninclude one or more of water-soluble polymers and cross-linkablewater-soluble polymers. Suitable water-soluble polymers andcross-linkable water-soluble polymers are disclosed in U.S. Pat. No.6,279,656, the entire disclosure of which is incorporated herein byreference. According to several exemplary embodiments in which thedegradable coating 104, 204 includes one or more of water-solublepolymers and cross-linkable water-soluble polymers, the solubilityparameters of such polymers can be controlled to adjust the timing ofthe solubility or degradation of the coating 104, 204. Such parameterscan include molecular weight, the hydrophilic/lipophilic balance of thepolymers, and the extent of cross-linking of the polymers. According toseveral exemplary embodiments, the degradable coating 104, 204 includesa degradable polymer such as polylactic acid, cellulose acetate, methylcellulose or combinations thereof that can degrade inside the hydraulicfracture to allow for the release of the infused chemical treatmentagent 102 at different time intervals.

According to one or more exemplary embodiments, the degradable coating104, 204 can degrade in any suitable manner. For example, the degradablecoating 204 can degrade from the outside-in, such that the outer surfaceof the coating 204 degrades first, resulting in controlled release ofchemical treatment agent 102 blended with the coating 204. Thesedegradable coating coatings 204 can include self-polishing coatings. Theself-polishing coatings can include self-polishing copolymers havingchemical bonds that are gradually hydrolyzed by water, such as producedwater, seawater, and/or saltwater. The self-polishing coating canrelease chemical treatment agents 102 gradually, over time, due to thenature of the degradation of the coating 204 from its outermost surfacetowards its innermost surface, the degradation caused by the coatingbeing gradually hydrolyzed by water.

According to several exemplary embodiments, the proppant particulates106 can be coated with a polymeric material that forms a semi-permeablepolymeric coating 104, 204 that is substantially non-degradable in thepresence of the well fluids but permits the chemical treatment agent toleach, elute, diffuse, bleed, discharge, desorb, dissolve, drain, seep,and leak through the polymeric coating so as to release the chemicaltreatment agent 102 into the fracture or well area. The amount andmolecular weight of the semi-permeable substantially non-degradablepolymeric coating 104, 204 can be varied to provide for longer orshorter release times for tailored release of the chemical treatmentagents 102. According to several exemplary embodiments, the proppantparticulates 106 are coated with a semi-permeable substantiallynon-degradable polymer such as phenol formaldehyde, polyurethane,cellulose ester, polyamides, vinyl esters, epoxies, or combinationsthereof.

The degradable shell 302 can be or include any material suitable toprevent or eliminate separation or release of the chemical treatmentagent(s) 106 from the encapsulated proppant 300, 400, 500 until thedegradable shell 302 degrades or breaks down. For example, thedegradable shell 102 can be impermeable or substantially impermeable tofracturing fluids, reservoir fluids, or the like until the degradableshell 302 degrades to a point that it becomes permeable to thesurrounding fluid(s). Once the degradable shell 302 becomes fluidpermeable, the chemical treatment agent(s) 106 can separate or elutefrom the encapsulated proppant 300, 400, 500.

The degradable shell 302 can be or include any water soluble and/orhydrocarbon soluble material. In one or more exemplary embodiments, thedegradable shell 302 can be or include the encapsulation materialsand/or sustained release compositions described in any one of U.S.Pre-Grant Publication Nos. 2003/0147821, 2005/0002996 and 2005/0129759,each incorporated by reference herein in its entirety. In one or moreexemplary embodiments, the degradable shell 302 can be or include fattyalcohols that include, but are not limited to, behenyl alcohol, caprylicalcohol, cetyl alcohol, cetaryl alcohol, decyl alcohol, lauryl alcohol,isocetyl alcohol, myristyl alcohol, oleyl alcohol, stearyl alcohol,tallow alcohol, steareth-2, ceteth-1, cetearth-3, and laureth-2. Thedegradable shell 302 can also be or include C₈-C₂₀ fatty acids thatinclude, but are not limited to, stearic acid, capric acid, behenicacid, caprylic acid, lauric acid, myristic acid, tallow acid, oleicacid, palmitic acid, and isostearic acid. The degradable shell 302 canalso be or include sorbitan derivatives that include, but are notlimited to, PEG-10 sorbitan laurate, PEG-20 sorbitan isostearate, PEG-3sorbitan oleate, polysorbate 40, sorbitan stearate, and sorbitanpalmitate. The degradable shell 302 can also be or include one or morewaxes that include, but are not limited to, mink wax, montan wax,carnauba wax, and candelilla wax, and synthetic waxes, such as siliconewaxes. In one or more exemplary embodiments, the degradable shell 302can be selected from polyoxymethylene urea (PMU), methoxymethyl methylolmelamine (MMM), polysaccharides, collagens, gelatins, alginates, guar,guar gum, gum Arabic, and agar and any combination or mixture thereof.The degradable shell 302 can also be or include any suitablethermoplastic material. In one or more exemplary embodiments, thedegradable shell 302 can be selected from polyvinyl alcohol,poly(acrylates and methacrylates), polylactic acid, polyamides,polyethylene, polypropylene, polystyrene, water-soluble polymers, andcross-linkable water-soluble polymers and any combination thereof.

In one or more exemplary embodiments, the degradable shell 302 can be athermoplastic material that degrades at any suitable time andtemperature. For example, the thermoplastic material can degrade attemperatures of at least about 5° C., at least about 10° C., at leastabout 20° C., at least about 30° C., at least about 50° C., at leastabout 70° C., or at least about 90° C. The thermoplastic material canalso degrade at temperatures of less than 100° C., less than 95° C.,less than 90° C., less than 80° C., or less than 70° C. Thethermoplastic material can also degrade at temperatures of from about 1°C., about 4° C., about 8° C., about 12° C., about 16° C., about 25° C.,about 35° C., about 45° C., or about 55° C. to about 75° C., about 85°C., about 95° C., about 105° C., about 120° C., about 150° C., or about200° C. or more. In one or more exemplary embodiments, the thermoplasticmaterial can degrade at temperatures of from about 1° C., about 4° C.,about 8° C., about 12° C., about 16° C., about 25° C., about 35° C.,about 45° C., or about 55° C. to about 75° C., about 85° C., about 95°C., about 105° C., about 120° C., about 150° C., or about 200° C. ormore within a time period ranging from about 10 seconds, about 30seconds, about 1 minute, about 2 minutes, about 5 minutes, about 10minutes, about 30 minutes, about 1 hour, or about 2 hours to about 5hours, about 10 hours, about 25 hours, about 50 hours, about 100 hours,about 500 hours, or about 1,000 hours or more.

According to one or more exemplary embodiments, the degradable shell 302can degrade in any suitable manner. For example, the degradable shell302 can degrade from the outside-in, such that the outer surface of thedegradable shell 302 degrades first, resulting in controlled release ofchemical treatment agent 106. The degradable shell 302 can also be aself-polishing coating as disclosed herein.

The degradable shell 302 can prevent the leaching, elution, diffusion,bleeding, discharging, desorption, dissolution, draining, seeping, orleaking of the chemical treatment agent 106 from the non-degradedencapsulated proppant, or encapsulated proppant particulates 300, 400,500. According to one or more exemplary embodiments, the chemicaltreatment agents 106 can leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, or leak from the encapsulated proppantparticulates 300, 400, 500 at a rate of less than 10 ppm/(gram*day),less than 5 ppm/(gram*day), less than 2 ppm/(gram*day), less than 1ppm/(gram*day), less than 0.5 ppm/(gram*day), less than 0.1ppm/(gram*day), or less than 0.05 ppm/(gram*day) for at least about 1hour, at least about 2 hours, at least about 6 hours, at least about 12hours, at least about 1 day, or at least about 2 days after beingadmixed with a hydraulic fracturing fluid. According to one or moreexemplary embodiments, the chemical treatment agent 106 can leach,elute, diffuse, bleed, discharge, desorb, dissolve, drain, seep, or leakfrom the encapsulated proppant particulates 300, 400, 500 at a rate ofless than 10 ppm/(gram*day), less than 5 ppm/(gram*day), less than 2ppm/(gram*day), less than 1 ppm/(gram*day), less than 0.5ppm/(gram*day), less than 0.1 ppm/(gram*day), or less than 0.05ppm/(gram*day) for at least about 1 hour, at least about 2 hours, atleast about 6 hours, at least about 12 hours, at least about 1 day, orat least about 2 days after contacting a subterranean formation. Forexample, the degradable shell 302 can limit the amount of leaching,elution, diffusion, bleeding, discharging, desorption, dissolution,draining, seeping, or leaking of the chemical treatment agent 106 fromthe encapsulated proppant particulates 1300, 400, 500 to less than 10ppm/gram, less than less than 5 ppm/gram, less than 1 ppm/gram, lessthan 0.5 ppm/gram, less than 0.1 ppm/gram, or less than less than 10ppb/gram for about 10 seconds, about 30 seconds, about 1 minute, about 2minutes, about 5 minutes, about 10 minutes, about 30 minutes, about 1hour, or about 2 hours to about 5 hours, about 10 hours, about 25 hours,about 50 hours, about 100 hours, about 500 hours, or about 1,000 hoursor more after being admixed with a hydraulic fracturing fluid and/or agravel-pack fluid. For example, the degradable shell 302 can limit theamount of leaching, elution, diffusion, bleeding, discharging,desorption, dissolution, draining, seeping, or leaking of the chemicaltreatment agent 106 from the encapsulated proppant particulates 300,400, 500 to less than 10 ppm/gram, less than less than 5 ppm/gram, lessthan 1 ppm/gram, less than 0.5 ppm/gram, less than 0.1 ppm/gram, or lessthan less than 10 ppb/gram for about 10 seconds, about 30 seconds, about1 minute, about 2 minutes, about 5 minutes, about 10 minutes, about 30minutes, about 1 hour, or about 2 hours to about 5 hours, about 10hours, about 25 hours, about 50 hours, about 100 hours, about 500 hours,or about 1,000 hours or more after contacting a subterranean formation.In one or more exemplary embodiments, the degradable shell 302 canprevent any leaching, elution, diffusion, bleeding, discharging,desorption, dissolution, draining, seeping, or leaking of the chemicaltreatment agent 106 from the encapsulated proppant particulates 300,400, 500 after being admixed with a hydraulic fracturing fluid and/orprior to contacting a subterranean formation.

According to several exemplary embodiments, the chemical treatment agent102 is released from the proppant particulates 106 for a period of up toabout one year, up to about five years, or up to about ten years afterthe proppant particulates 106 are placed in a fracture in a subterraneanformation.

According to several exemplary embodiments, the proppant particulates106 can be coated or encapsulated with one or more water-solublechemical treatment agents 102 such as a scale inhibitor, a saltinhibitor, or combinations or mixtures thereof, and then further coatedor encapsulated with one or more hydrocarbon-soluble chemical treatmentagents 102 such as a paraffin inhibitor or asphaltene inhibitor, toprovide the coated proppant particulates 100, 200 and/or theencapsulated proppant particulates 300, 400, 500. The coating ofhydrocarbon-soluble chemical treatment agents 102 can be mixed with ordisposed or layered around the coating of water-soluble chemicaltreatment agents. According to such embodiments, the coated proppantparticulates 100, 200 and/or the encapsulated proppant particulates 300,400, 500 are placed in a fracture in a subterranean formation and oncehydrocarbon production begins, the presence of the hydrocarbons causesleaching, elution, diffusion, bleeding, discharging, desorbing,dissolving, draining, seeping, or leaking of the hydrocarbon-solublechemical treatment agent 102 from the coated proppant particulates 100,200 and/or the encapsulated proppant particulates 300, 400, 500. After acertain period of time, when water production begins, then thewater-soluble chemical treatment agent 102 begins to leach, elute,diffuse, bleed, discharge, desorb, dissolve, drain, seep, or leak fromthe coated proppant particulates 100, 200 and/or the encapsulatedproppant particulates 300, 400, 500.

According to several exemplary embodiments, the proppant particulates106 can be coated or encapsulated with one or more hydrocarbon-solublechemical treatment agents 102 such as a paraffin inhibitor or asphalteneinhibitor, and then further coated or encapsulated with one or morewater-soluble chemical treatment agents 102 such as a scale inhibitor, asalt inhibitor, or combinations or mixtures thereof, to provide thecoated proppant particulates 100, 200 and/or the encapsulated proppantparticulates 300, 400, 500. The coating of water-soluble chemicaltreatment agents 102 can be mixed with or disposed or layered around thecoating of the hydrocarbon-soluble chemical treatment agents 102.According to such embodiments, the coated proppant particulates 100, 200and/or the encapsulated proppant particulates 300, 400, 500 are placedin a fracture in a subterranean formation and once water productionbegins, the presence of water causes leaching, elution, diffusion,bleeding, discharging, desorbing, dissolving, draining, seeping, orleaking of the water-soluble chemical treatment agent 102 from thecoated proppant particulates 100, 200 and/or the encapsulated proppantparticulates 300, 400, 500. After a certain period of time, whenhydrocarbon production begins, then the hydrocarbon-soluble chemicaltreatment agent 102 begins to leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, or leak from the coated proppantparticulates 100, 200 and/or the encapsulated proppant particulates 300,400, 500.

According to several exemplary embodiments, the proppant particulates106 are porous ceramic proppant particulates that can be infused withone or more water-soluble chemical treatment agents 102 such as a scaleinhibitor, a salt inhibitor, or combinations or mixtures thereof, andthen coated or encapsulated with one or more hydrocarbon-solublechemical treatment agents 102 such as a paraffin inhibitor or asphalteneinhibitor, to provide the coated proppant particulates 100, 200 and/orthe encapsulated proppant particulates 300, 400, 500. According to suchembodiments, the coated proppant particulates 100, 200 and/or theencapsulated proppant particulates 300, 400, 500 are placed in afracture in a subterranean formation and once hydrocarbon productionbegins, the presence of the hydrocarbons causes leaching, elution,diffusion, bleeding, discharging, desorbing, dissolving, draining,seeping, or leaking of the hydrocarbon-soluble chemical treatment agent102 from the coated proppant particulates 100, 200 and/or theencapsulated proppant particulates 300, 400, 500. After a certain periodof time, when water production begins, then the water-soluble chemicaltreatment agent 102 begins to leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, or leak from the coated proppantparticulates 100, 200 and/or the encapsulated proppant particulates 300,400, 500.

According to several exemplary embodiments, the proppant particulates106 are porous ceramic proppant particulates that can be infused withone or more hydrocarbon-soluble chemical treatment agents 102 such as aparaffin inhibitor or asphaltene inhibitor, and then coated orencapsulated with one or more water-soluble chemical treatment agents102 such as a scale inhibitor, a salt inhibitor, or combinations ormixtures thereof, to provide the coated proppant particulates 100, 200and/or the encapsulated proppant particulates 300, 400, 500. Accordingto such embodiments, the coated proppant particulates 100, 200 and/orthe encapsulated proppant particulates 300, 400, 500 are placed in afracture in a subterranean formation and once water production begins,the presence of water causes leaching, elution, diffusion, bleeding,discharging, desorbing, dissolving, draining, seeping, or leaking of thewater-soluble chemical treatment agent 102 from the coated proppantparticulates 100, 200 and/or the encapsulated proppant particulates 300,400, 500. After a certain period of time, when hydrocarbon productionbegins, then the hydrocarbon-soluble chemical treatment agent 102 beginsto leach, elute, diffuse, bleed, discharge, desorb, dissolve, drain,seep, or leak from the coated proppant particulates 100, 200 and/or theencapsulated proppant particulates 300, 400, 500.

The chemical treatment agents 102 can leach, elute, diffuse, bleed,discharge, desorb, dissolve, drain, seep, or leak from the coatedproppant particulates 100, 200 at any suitable rate. The chemicaltreatment agents 102 can also leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, or leak from the encapsulated proppantparticulates 300, 400, 500 at any suitable rate once the degradableshell 302 becomes fluid permeable. For example, the chemical treatmentagents 102 can leach, elute, diffuse, bleed, discharge, desorb,dissolve, drain, seep, or leak from the coated proppant particulates100, 200 and/or the encapsulated proppant particulates 300, 400, 500 ata rate of at least about 0.1 ppm/(gram*day), at least about 0.3ppm/(gram*day), at least about 0.7 ppm/(gram*day), at least about 1.25ppm/(gram*day), at least about 2 ppm/(gram*day), at least about 3ppm/(gram*day), at least about 5 ppm/(gram*day), at least about 10ppm/(gram*day), at least about 20 ppm/(gram*day), at least about 40ppm/(gram*day), at least about 75 ppm/(gram*day), or at least about 100ppm/(gram*day) for at least about 2 weeks, at least about 1 month, atleast about 2 months, at least about 6 months, at least about 9 months,at least about 1 year, or at least about 2 years. For example, thechemical treatment agents can elute from the coated proppantparticulates 100, 200 and/or the encapsulated proppant particulates 300,400, 500 at a rate from about 0.01 ppm/(gram*day), about 0.05ppm/(gram*day), about 0.1 ppm/(gram*day), about 0.5 ppm/(gram*day),about 1 ppm/(gram*day), about 1.5 ppm/(gram*day), about 2ppm/(gram*day), or about 3 ppm/(gram*day) to about 4 ppm/(gram*day),about 4.5 ppm/(gram*day), about 5 ppm/(gram*day), about 6ppm/(gram*day), about 7 ppm/(gram*day), about 8 ppm/(gram*day), about 10ppm/(gram*day), about 15 ppm/(gram*day), about 30 ppm/(gram*day), about75 ppm/(gram*day), or about 150 ppm/(gram*day) for at least about 2weeks, at least about 1 month, at least about 2 months, at least about 6months, at least about 9 months, at least about 1 year, or at leastabout 2 years.

According to one or more exemplary embodiments, the scale inhibitor canleach, elute, diffuse, bleed, discharge, desorb, dissolve, drain, seep,or leak from the coated proppant particulates 100, 200 and/or theencapsulated proppant particulates 300, 400, 500 at a rate of at leastabout 0.1 ppm/(gram*day), at least about 0.3 ppm/(gram*day), at leastabout 0.7 ppm/(gram*day), at least about 1.25 ppm/(gram*day), at leastabout 2 ppm/(gram*day), at least about 3 ppm/(gram*day), at least about5 ppm/(gram*day), at least about 10 ppm/(gram*day), at least about 20ppm/(gram*day), at least about 40 ppm/(gram*day), at least about 75ppm/(gram*day), or at least about 100 ppm/(gram*day) for at least about2 weeks, at least about 1 month, at least about 2 months, at least about6 months, at least about 9 months, at least about 1 year, or at leastabout 2 years. For example, the scale inhibitor can elute from thecoated proppant particulates 100, 200 and/or the encapsulated proppantparticulates 300, 400, 500 at a rate from about 0.01 ppm/(gram*day),about 0.05 ppm/(gram*day), about 0.1 ppm/(gram*day), about 0.5ppm/(gram*day), about 1 ppm/(gram*day), about 1.5 ppm/(gram*day), about2 ppm/(gram*day), or about 3 ppm/(gram*day) to about 4 ppm/(gram*day),about 4.5 ppm/(gram*day), about 5 ppm/(gram*day), about 6ppm/(gram*day), about 7 ppm/(gram*day), about 8 ppm/(gram*day), about 10ppm/(gram*day), about 15 ppm/(gram*day), about 30 ppm/(gram*day), about75 ppm/(gram*day), or about 150 ppm/(gram*day) for at least about 2weeks, at least about 1 month, at least about 2 months, at least about 6months, at least about 9 months, at least about 1 year, or at leastabout 2 years.

According to one or more exemplary embodiments, the paraffin inhibitorcan leach, elute, diffuse, bleed, discharge, desorb, dissolve, drain,seep, or leak from the coated proppant particulates 100, 200 and/or theencapsulated proppant particulates 300, 400, 500 at a rate of at leastabout 0.1 ppm/(gram*day), at least about 0.3 ppm/(gram*day), at leastabout 0.7 ppm/(gram*day), at least about 1.25 ppm/(gram*day), at leastabout 2 ppm/(gram*day), at least about 3 ppm/(gram*day), at least about5 ppm/(gram*day), at least about 10 ppm/(gram*day), at least about 20ppm/(gram*day), at least about 40 ppm/(gram*day), at least about 75ppm/(gram*day), or at least about 100 ppm/(gram*day) for at least about2 weeks, at least about 1 month, at least about 2 months, at least about6 months, at least about 9 months, at least about 1 year, or at leastabout 2 years. For example, the paraffin inhibitor can elute from thecoated proppant particulates 100, 200 and/or the encapsulated proppantparticulates 300, 400, 500 at a rate from about 0.01 ppm/(gram*day),about 0.05 ppm/(gram*day), about 0.1 ppm/(gram*day), about 0.5ppm/(gram*day), about 1 ppm/(gram*day), about 1.5 ppm/(gram*day), about2 ppm/(gram*day), or about 3 ppm/(gram*day) to about 4 ppm/(gram*day),about 4.5 ppm/(gram*day), about 5 ppm/(gram*day), about 6ppm/(gram*day), about 7 ppm/(gram*day), about 8 ppm/(gram*day), about 10ppm/(gram*day), about 15 ppm/(gram*day), about 30 ppm/(gram*day), about75 ppm/(gram*day), or about 150 ppm/(gram*day) for at least about 2weeks, at least about 1 month, at least about 2 months, at least about 6months, at least about 9 months, at least about 1 year, or at leastabout 2 years.

The coated proppant particulates 100, 200 and/or the encapsulatedproppant particulates 300, 400, 500 can also be coated and/or infusedwith a surfactant and/or nanoparticle dispersion as disclosed herein sothat the proppant particulates 106 act as a carrier for the surfactantand/or nanoparticle dispersion in a hydraulic fracturing operation. Theuse of a surfactant and/or nanoparticle dispersion that is coated ontothe proppant itself, rather than simply pumped into a formation, asdiscussed above, offers improved wetting characteristics. The selectionof a specific nanoparticle dispersion or surfactant to be coated onand/or infused into the proppant particulates 106 depends on thenecessary adjustment in wetting characteristics of the proppant for thedesired production enhancement. According to several exemplaryembodiments, the nanoparticle dispersions or surfactants can be releasedfrom the coated proppant particulates 100, 200 and/or the encapsulatedproppant particulates 300, 400, 500 when the degradable coating 104and/or degradable shell 302 dissolves in aqueous or hydrocarbon fluids.According to such embodiments, upon degradation of the coating 104and/or shell 302, some of the nanoparticle dispersions or surfactantsare released upon exposure to passing fluids, and therefore improve thewettability of formation surfaces. The portion of the nanoparticledispersions or surfactants remaining in the proppant would improve thewettability of the proppant itself.

Modifying wettability of the proppant can also reduce conductivity losscaused by fracturing fluids, control the relative permeability to flowof fluids which can be encountered in the reservoir, to “lubricate” theproppant to allow more efficient proppant arrangement when the fracturecloses, and to reduce eventual scale buildup on proppant. Modifyingwettability of the proppant can also provide significant flow benefitsunder multiphase flow as evidenced by trapped gas saturation, alteredsurface tension/contact angles, and electrostatic charges on theproppant. Proppant particulates 106 modified to have an “oil-wet”surface can be ideal in a gas well producing water, while proppantparticulates 106 with a different wettability can give preferential flowto oil and reduce watercut.

The surfactant and/or nanoparticle dispersion can also leach, elute,diffuse, bleed, discharge, desorb, dissolve, drain, seep, or leak fromthe coated proppant particulates 100, 200 and/or the encapsulatedproppant particulates 300, 400, 500 at any suitable rate. According toone or more exemplary embodiments, the surfactant and/or nanoparticledispersion can leach, elute, diffuse, bleed, discharge, desorb,dissolve, drain, seep, or leak from the coated proppant particulates100, 200 and/or the encapsulated proppant particulates 300, 400, 500 ata rate of at least about 0.1 ppm/(gram*day), at least about 0.3ppm/(gram*day), at least about 0.7 ppm/(gram*day), at least about 1.25ppm/(gram*day), at least about 2 ppm/(gram*day), at least about 3ppm/(gram*day), at least about 5 ppm/(gram*day), at least about 10ppm/(gram*day), at least about 20 ppm/(gram*day), at least about 40ppm/(gram*day), at least about 75 ppm/(gram*day), or at least about 100ppm/(gram*day) for at least about 2 weeks, at least about 1 month, atleast about 2 months, at least about 6 months, at least about 9 months,at least about 1 year, or at least about 2 years. For example, thesurfactant and/or nanoparticle dispersion can elute from the coatedproppant particulates 100, 200 and/or the encapsulated proppantparticulates 300, 400, 500 at a rate from about 0.01 ppm/(gram*day),about 0.05 ppm/(gram*day), about 0.1 ppm/(gram*day), about 0.5ppm/(gram*day), about 1 ppm/(gram*day), about 1.5 ppm/(gram*day), about2 ppm/(gram*day), or about 3 ppm/(gram*day) to about 4 ppm/(gram*day),about 4.5 ppm/(gram*day), about 5 ppm/(gram*day), about 6ppm/(gram*day), about 7 ppm/(gram*day), about 8 ppm/(gram*day), about 10ppm/(gram*day), about 15 ppm/(gram*day), about 30 ppm/(gram*day), about75 ppm/(gram*day), or about 150 ppm/(gram*day) for at least about 2weeks, at least about 1 month, at least about 2 months, at least about 6months, at least about 9 months, at least about 1 year, or at leastabout 2 years.

In an exemplary method of fracturing a subterranean formation, ahydraulic fluid is injected into the formation at a rate and pressuresufficient to open a fracture therein, and a fluid containing a proppantcomposition including one or more coated proppant particulates 100, 200and/or encapsulated proppant particulates 300, 400, 500 containing theone or more chemical treatment agents 102, as described herein andhaving one or more of the properties as described herein is injectedinto the fracture to prop the fracture in an open condition.

According to several exemplary embodiments, a method of diagnosticevaluation of a hydraulic fracturing operation is provided, the methodincluding: 1) injecting a hydraulic fluid into the subterraneanformation at a rate and pressure sufficient to open a fracture therein,and 2) injecting a proppant composition into the subterranean formation,wherein the proppant composition includes coated proppant particulates100, 200 and/or encapsulated proppant particulates 300, 400, 500, 3)wherein the chemical treatment agent 102 separates from the proppantparticulate 106 over an extended period of time, 4) wherein the chemicaltreatment agent 102 returns to the surface with the produced fluids, and5) wherein the chemical treatment agent 102 is recovered and identified.According to several exemplary embodiments, the chemical treatment agent102 is a biological marker, or biological tag.

According to several exemplary embodiments, in order to add porous,chemically infused ceramic proppant to standard non-porous ceramicproppant in a hydraulic fracture in a way that does not impair thepermeability or conductivity of the standard non-porous ceramic proppantalone, requires the use of a combination of different types of ceramicproppants for the standard non-porous and porous portions of the totalceramic proppant mass utilized in the fracturing operation. Forinstance, according to several exemplary embodiments of the presentinvention, if the standard non-porous particulate selected is a lightweight ceramic proppant, the porous ceramic particulate can be either anintermediate density ceramic proppant or a high density ceramicproppant. Also, according to several exemplary embodiments of thepresent invention, if the standard non-porous particulate selected is anintermediate density proppant, the porous ceramic particulate can be ahigh density ceramic proppant.

For example, the fraction of intermediate density porous ceramicproppant to be added to a standard non-porous light weight ceramicproppant will dictate the maximum porosity that the intermediate densityporous ceramic may have and not negatively impact permeability. In thisexample, if a 10% fraction of intermediate density porous proppant is tobe added to a standard light weight ceramic proppant then the maximumporosity of the intermediate density porous proppant may be 12% in orderto not reduce the permeability of the proppant as compared to thepermeability of the standard light weight ceramic proppant alone whereasadding a 10% fraction of an intermediate density porous proppant having20% porosity may be detrimental to proppant permeability.

FIG. 6 is a graphical comparison of the permeability of light weightceramic proppant, intermediate density ceramic proppant, and highdensity ceramic proppant. As shown in FIG. 6, a high density ceramicproppant has a higher permeability than an intermediate density ceramicproppant which in turn has a higher permeability than a light weightceramic proppant. This variability results from the crystallinestructure differences arising from the difference in composition of thestarting raw materials. FIG. 7 is a graphical representation of the longterm permeability of a standard non-porous light weight ceramic proppantand a light weight porous ceramic proppant (at 25% porosity). Standardceramic proppants are generally manufactured so as to eliminate as muchporosity as is practically possible in the individual particulates inorder to maximize the inherent strength of the particles. This isconsistent with the nature of ceramic bodies in that they tend to failas a function of the size of the largest internal flaw and in thiscontext an internal open pore space is a flaw. Consequently, in ageneral sense, the lower the internal porosity with small pore sizes,the stronger the ceramic body. Conversely, in a general sense, thegreater the overall amount of internal porosity and large pore size of aceramic particulate the weaker will be its inherent strength. Thus, theconductivity of a light weight ceramic proppant in which there is 10%porosity in the particle will be lower than the conductivity of alightweight ceramic proppant having 5% porosity which in turn will belower than a non-porous light weight ceramic proppant.

Further, the comparison shown in FIG. 6 for non-porous ceramicparticulates can be duplicated for porous ceramic particulates.Specifically, a high density porous ceramic proppant that has a porosityof the particulate of 12% will have a higher permeability than anintermediate density ceramic proppant with 12% particulate porosity,which in turn will have a higher permeability than a light weightceramic proppant with 12% particulate porosity.

According to several exemplary embodiments, the porous, chemicallyinfused porous ceramic proppant may have a similar alumina content asthe standard non-porous ceramic proppant and can be added to thestandard non-porous ceramic proppant in a hydraulic fracture in a waythat does not impair the permeability or conductivity of the standardnon-porous ceramic proppant alone. According to several exemplaryembodiments, the porous, chemically infused porous ceramic proppant mayhave a higher alumina concentration compared to that of the standardnon-porous ceramic proppant and can be added to the standard non-porousceramic proppant in a hydraulic fracture in a way that does not impairthe permeability or conductivity of the standard non-porous ceramicproppant alone. According to such embodiments, the porous and non-porousproppants can be processed in different ways such that the mechanicalproperties of the chemically infused porous ceramic proppant isapproximately the same as or better that the mechanical properties ofthe standard non-porous ceramic proppant.

A ceramic proppant composition containing a mixture of porous ceramicproppant and non-porous ceramic proppant can have a conductivity that isat least about 10%, at least about 20%, at least about 30%, at leastabout 40%, at least about 50%, at least about 60%, at least about 70%,at least about 80%, at least about 90%, at least about 95%, or at leastabout 99% of the conductivity of the non-porous ceramic proppant. Forexample, the ceramic proppant composition containing a mixture of porousceramic proppant and non-porous ceramic proppant can have a conductivityfrom about 25% to about 125%, about 55% to about 115%, about 65% toabout 112%, about 75% to about 108%, about 85% to about 105%, about 95%to about 105%, or about 99.99% to about 102% of the conductivity of thenon-porous ceramic proppant.

As noted above, ceramic proppants can be manufactured to a range ofapparent specific gravities and such range of specific gravitiesreflects the range of internal porosity present in the ceramic pellets.The internal porosity of commercial ceramic proppant is oftentimes low(generally less than 5% and this internal porosity is notinterconnected). As disclosed in U.S. Pat. No. 7,036,591, however, theprocessing of ceramic proppants can be altered to generate within theindividual ceramic pellet a porosity exceeding 30%. As pellet porosityexceeds about 5%, the porosity of the pellet becomes interconnected.According to several exemplary embodiments, the internal interconnectedporosity in the porous ceramic proppant can be infused with a chemicaltreatment agent. Methods for infusing a porous ceramic proppants arewell known to those of ordinary skill in the art, for instance see U.S.Pat. No. 5,964,291 and U.S. Pat. No. 7,598,209, and similar processessuch as vacuum infusion, thermal infusion, capillary action, ribbonblending at room or elevated temperature, microwave blending or pug millprocessing can be utilized to infuse porous ceramic proppants withchemical treatment agents according to several exemplary embodiments ofthe present invention.

As noted above, the internal porosity in porous ceramic proppantparticulates 106 can be infused with a chemical treatment agent 102 suchas a tracer material so that the porous ceramic particulates 106 act asa carrier for the tracer in a hydraulic fracturing operation. Bytailoring the type of porous ceramic particulates 106 used as a carrier,according to the methods discussed above, any potential impact toproppant conductivity by using the porous ceramic particulates 106 canbe avoided. According to certain embodiments of the present invention,the tracer material includes metallic or non-metallic nano-particleswhile in other embodiments, the tracer material includes a chemicaltracer.

In one or more exemplary embodiments, the chemical treatment agents 102include one or more radio-frequency identification (RFID) tags. The RFIDtag can be included on and/or in any of the proppant particulates 106disclosed herein in any manner disclosed herein. The RFID tag can becoated on and/or infused into the porosity of the proppant, for examplethe porous ceramic proppant particulates 106. The RFID tags can have anysuitable size. For example, the RFID tag can have a size suitable forinfusing the RFID tag into one or more pores of the porous ceramicproppant particulates 106. In one or more exemplary embodiments, theRFID tag can have a size range from about 10 nm to about 2 mm, measuredin its largest dimension. In one or more exemplary embodiments, theinfused RFID tags can elute from the porous ceramic proppantparticulates 106 located in a subterranean environment and reliablycarried to the surface in produced fluid. The produced fluid can bewater or a hydrocarbon and RFID tracer can be infused with thewater-soluble or hydrocarbon-soluble resin materials disclosed herein sothat the RFID tags elute in the presence of produced water or producedhydrocarbons. The RFID tags can be passive RFID tags or active RFIDtags. For example, a passive RFID tag can elute from the proppantparticulate as disclosed above and activated at or near the surface by apower source located at or near the surface to cause a signal to emitfrom the RFID tag. After activation, the RFID tag can emit a signal thatcan be recorded, decoded, and/or analyzed at or near the surface todetermine which zone(s) are producing and whether water or hydrocarbonsare being produced from the respective zone(s).

According to several exemplary embodiments, the chemical treatmentagents 102 can be or include chemical tracer materials, such as thebiological tags described in International Patent Publication No.WO2007/132137, various dyes, fluorescent materials, as well asbiological markers, such as DNA. Other chemical tracers can includefluorine substituted compounds. According to several exemplaryembodiments, in order to ensure the tracer is reliably carried to thesurface in produced fluid, the tracer is soluble in the produced fluid.The produced fluid can be water or a hydrocarbon and there are availabletracers that are only soluble in water or only soluble in liquidhydrocarbon or only soluble in hydrocarbon gases. This variablesolubility allows for more definitive diagnostic capabilities. Forexample hydraulic fracturing is often performed in stages. That is, theentire hydrocarbon bearing interval to be hydraulically fractured is notstimulated at one time but rather in stages. In the case of a horizontalwell, as many as forty separate hydraulic fracturing operations, orstages, can be conducted in the horizontal section. Because each stageof hydraulic fracturing entails additional cost, it is of interest todetermine how many of the stages are contributing to production from thewell and further which contributing stages are producing hydrocarbonsand which are producing water. The use of distinctive tracer materialscan accomplish this objective. For example, if a well is hydraulicallyfractured in five stages and it is of diagnostic importance to determinewhich of the stages are producing liquid hydrocarbons and which of thestages are producing water, then there can be introduced into theproppant for stage 1 a fraction thereof containing a unique liquidhydrocarbon-soluble Tracer 1H. Also, there can be added to this stage, afraction of the proppant that contains a unique water-soluble Tracer 1W.For the second stage of the hydraulic fracturing operation, then therecan be introduced into the proppant for stage 2 a fraction containing aunique liquid hydrocarbon soluble Tracer 2H. Also, there can be added tothis stage a fraction of the proppant containing a unique water-solubleTracer 2W. This method of adding uniquely distinguishablehydrocarbon-soluble and water-soluble tracers contained within and/or onthe proppant particulates can continue for all or a portion of thesubsequent stages. When the well is then placed on production followingthe completion of the hydraulic fracturing operations, samples of theproduced water and hydrocarbons can then be captured at different pointsin time following the start of production and analyzed for the presenceof the unique tracer materials. By determining the presence and relativeconcentration of each of the tracer materials, diagnostic determinationscan be made of effectiveness of the stimulation and the hydrocarboncontent of the stimulated formation. This diagnostic information canthen be utilized to optimize subsequent hydraulic fracturing operationsin nearby wells.

Coating the biological marker onto the proppant particulates and/orinfusing the biological marker into the proppant particulates 106,rather than adding the biological marker directly to the fracturefluids, permits a long term diagnostic capability not otherwiseavailable. When the marker is added directly to the fracture fluid itwill flow back immediately with the fluid when the well is placed onproduction because there is no mechanism for the marker to remain in thewell. Thus, the diagnostic benefits of adding the marker directly to thefracture fluid are limited. Conversely, when the biological marker iscoated onto and/or infused into proppant particulates 106, the elutionof the marker is slow and can be controlled by one or both of thecharacteristics of the porosity of the proppant grain or by the additionof a permeable coating on the proppant particulates 106 to delay therelease of the biological marker.

In order for the biological marker to be reliably carried to the surfacein produced fluid, the biological marker must be capable of eluting fromthe proppant particulate 106 and partitioning into the produced fluidwhich may be a water-based or hydrocarbon-based fluid. According toseveral exemplary embodiments, the biological marker can be encapsulatedto preferentially partition into either or both water and hydrocarbonphases, depending on the diagnostic goals. This variable partitioningallows for more definitive diagnostic capabilities. For example, asmentioned above, hydraulic fracturing is often performed in stages. Thatis, the entire hydrocarbon bearing interval to be hydraulicallyfractured is not stimulated at one time but rather in stages. In thecase of a horizontal well as many as 40 separate hydraulic fracturingoperations may be conducted in the horizontal well. Because each stageof hydraulic fracturing entails additional cost, it is of interest todetermine how many of the stages are contributing to production from thewell and further which contributing stages are producing hydrocarbonsand which are producing water.

According to several exemplary embodiments, the biological marker(s)disclosed herein can be used to accomplish this objective. For example,according to several exemplary embodiments, if a well is hydraulicallyfractured in five stages and it is of diagnostic importance to determinewhich of the stages are producing hydrocarbons and which of the stagesare producing water, then the proppant particulates 106 can contain forthe first stage a unique hydrocarbon-partitioning biological marker,such as an encapsulated synthetic DNA with a known sequence. Also, therecan be added to the first stage one or more proppant particulates 106containing a unique water-partitioning biological marker. For the secondstage of the hydraulic fracturing operation, then the proppantparticulates 106 can contain a different unique hydrocarbon-partitioningbiological marker. Also, there can be added to the second stage one ormore proppant particulates 106 can contain a different, uniquewater-partitioning biological marker. According to several exemplaryembodiments, this method of utilizing different uniquely distinguishablehydrocarbon- and water-partitioning biological markers that arecontained on and/or in the proppant particulates 106 can continue forall or a portion of the subsequent stages. In addition to determiningwhich stages of a hydraulically fractured well are producinghydrocarbons and/or water it may be desirable to determine the fractionof the created fracture that is contributing to the flow of fluids.Estimates of the length and heights of the created fracture are possibleby various means well known to those of ordinary skill in the art.Fracture lengths of several hundred feet and heights of 50 feet or moreare common. Further it is also well established that the entire lengthand height of the created fracture may not contribute to production fromthe well. This lack of contribution can be determined by a number ofmethods well known to those of ordinary skill in the art. To the extentthe entire fracture does not contribute to flow, the cost to create thenon-contributing portion is wasted or conversely failure of a portion ofthe fracture to contribute may result in a reduction of producedhydrocarbons from the well. Thus, it is valuable to assess the fractionof the created fracture contributing to flow. Such knowledge can lead tooptimization of the design of subsequent hydraulic fracturingoperations. This can be accomplished by incorporating one or moreproppant particulates 106 containing a unique water and/or hydrocarbonpartitioning biological marker within a segment of the proppant beingpumped in a particular stage and then incorporating one or more proppantparticulates 106 containing a different unique water and/or hydrocarbonpartitioning biological marker within a second a segment of the proppantbeing pumped in the same stage. This method can be replicated for asmany segments of the stage one desires to interrogate. In the case of a40 stage hydraulic fracturing operation where it is desirable todetermine the contribution of both hydrocarbons and water from eachstage as well as the hydrocarbon and water contribution from 5 segmentsof each stage, then 400 unique biological markers are required.

According to several exemplary embodiments, when the well is placed onproduction following the completion of the hydraulic fracturingoperations, the biological marker will elute from the proppantparticulates 106 and will partition into one or both of the producedhydrocarbons and water. Samples of the produced water and hydrocarbonsare then captured at different points in time and analyzed for thepresence of the unique biological markers. By identifying the presenceand relative concentration of each of the biological markers, diagnosticdeterminations can be made of the effectiveness of the stimulation andthe hydrocarbon or water productivity of the stimulated formation. Thisdiagnostic information can then be utilized to optimize subsequenthydraulic fracturing operations in nearby wells.

In order to accomplish this, and according to several exemplaryembodiments, the biological marker separates from the proppantparticulates 106 after the proppant particulates are injected into thefracture. In several exemplary embodiments, separation of the biologicalmarker from the proppant particulates 106 can be accomplished by thebiological marker leaching, eluting, diffusing, bleeding, discharging,draining, seeping, or leaking out of the proppant, or any combinationthereof. Further, this leaching, eluting, diffusing, bleeding,discharging, draining, seeping, or leaking out of the proppant, or anycombination thereof can be further controlled by a permeable coating104.

As mentioned above, the partitioning of the biological marker, i.e.,whether into the hydrocarbon or water phase, can be tailored based onthe needs of the fracturing operation by tailoring the encapsulationmaterial. If, for example, diagnostic information is needed about ahydrocarbon-producing section of the well, a proppant particulate 106can be infused and/or coated with an encapsulatedhydrocarbon-partitioning biological marker, which will then separatefrom the proppant into the surrounding hydrocarbon fluids. Conversely,if diagnostic information is needed about a water-producing section ofthe well, a proppant particulate can be infused and/or coated with anencapsulated water-partitioning biological marker, which will thenseparate from the proppant into the water.

The biological marker 102 can leach, elute, diffuse, bleed, discharge,desorb, dissolve, drain, seep, or leak from the coated proppantparticulates 100, 200 and/or the encapsulated proppant particulates 300,400, 500 at any suitable rate. According to one or more exemplaryembodiments, the biological marker can leach, elute, diffuse, bleed,discharge, desorb, dissolve, drain, seep, or leak from the coatedproppant particulates 100, 200 and/or the encapsulated proppantparticulates 300, 400, 500 at a rate of at least about 0.1ppm/(gram*day), at least about 0.3 ppm/(gram*day), at least about 0.7ppm/(gram*day), at least about 1.25 ppm/(gram*day), at least about 2ppm/(gram*day), at least about 3 ppm/(gram*day), at least about 4ppm/(gram*day), at least about 6 ppm/(gram*day), or at least about 8ppm/(gram*day) for at least about 2 weeks, at least about 1 month, atleast about 2 months, at least about 6 months, at least about 9 months,at least about 1 year, or at least about 2 years. For example, thebiological marker 102 can elute from the coated proppant particulates100, 200 and/or the encapsulated proppant particulates 300, 400, 500 ata rate from about 0.01 ppm/(gram*day), about 0.05 ppm/(gram*day), about0.1 ppm/(gram*day), about 0.5 ppm/(gram*day), about 1 ppm/(gram*day),about 1.5 ppm/(gram*day), about 2 ppm/(gram*day), or about 3ppm/(gram*day) to about 4 ppm/(gram*day), about 4.5 ppm/(gram*day),about 5 ppm/(gram*day), about 6 ppm/(gram*day), about 7 ppm/(gram*day),about 8 ppm/(gram*day), about 10 ppm/(gram*day), about 15ppm/(gram*day), about 30 ppm/(gram*day), or about 75 ppm/(gram*day) forat least about 2 weeks, at least about 1 month, at least about 2 months,at least about 6 months, at least about 9 months, at least about 1 year,or at least about 2 years.

According to several exemplary embodiments, after the chemical treatmentagent 102, such as a biological marker separates from the proppant andpartitions into a production fluid, the production fluid will thentransport the biological marker to the surface. Once the productionfluids reach the surface, the fluids can be analyzed for the presence ofthe biological marker.

According to several exemplary embodiments, the chemical treatment agent102 includes one or more biological markers having unique identifiersand the unique identifier of the one or more biological markers islogged before the one or more markers is injected into the fracture. Inseveral exemplary embodiments when multiple biological markers are usedacross one or all of the stages of a fracture, this log will enable thewell operator to match the biological marker in the production fluid tothe section of the fracture where it was produced. For example, if threeunique DNA markers are injected into stages 1, 2, and 3, respectively,of a hydraulic fracturing stimulation operation, the unique identifyingbase sequence of each DNA marker injected into stages 1, 2, and 3 willbe recorded. If DNA is detected in the production fluids at the surface,the sequence of the returned DNA can be compared to the log to determinewhich stage produced the DNA. Relative amounts of each marker can beused to quantitatively estimate the relative volumes of the producedfluids from each of the stages. Identification and detection of DNAsequences is well known in the art and many companies manufacture“off-the-shelf” identification and detection assays. For example, DNAdetection and identification assays and kits are available commerciallyfrom Molecular Devices, LLC and Illumina, Inc. Further, DNA replicationmethodologies are well known to those of ordinary skill in the art. Thispermits extremely low levels of DNA present in the produced fluids,which may be below detection limits, to be identified by first employinga replication procedure to increase the concentration of the DNA beyonddetection limits. Because the replication methods proportionallyincrease all DNA present, the relative amount of the individual DNAmarkers present is not altered.

According to several exemplary embodiments, once the biological markersare recovered from the production fluids and identified, a comparativeanalysis of the amount of biological marker from each stage or stagesegment in the sample can then be related to the amount of hydrocarbonor water produced from that section. For example, the relativehydrocarbon or water volume contribution of a stage or stages of theformation can be estimated based on the amount of biological markersrecovered, i.e. with more hydrocarbon or water produced from that stageresulting in more biological detection from that stage. Additionally,the relative hydrocarbon or water volume contribution of a segment of astage can be estimated based on the amount of biological markersrecovered from the segment of the stage. Based on this analysis, adiagnostic log across multiple stages of a fractured formation can bedeveloped, giving a well operator detailed knowledge about theproduction volume (or lack thereof) of the entire fractured formation.This analysis can likewise be repeated periodically over an extendedtimeframe to establish trends in the production performance of the wellproviding diagnostic information that is not now available with existingtechnologies.

According to several exemplary embodiments, the coated proppantparticulates 100, 200 are prepared according to a two-step process. Inthe first step, a chemical treatment agent 102 is infused into theporous ceramic proppant particulates 106. In the second step, theinfused porous ceramic proppant particulates 106 are coated with asemi-permeable substantially non-degradable polymer coating 104, 204. Inseveral exemplary embodiments, the chemical treatment agent 102 isinfused into the porous ceramic proppant particulates 106 by vacuuminfusion. In other exemplary embodiments, the chemical treatment agent102 is infused into the porous ceramic proppant particulates 106 using athermal infusion process whereby the porous ceramic proppantparticulates 106 are heated and wetted with a solution containing thechemical treatment agent 102. As the porous ceramic proppantparticulates 106 cool, capillary action causes the chemical treatmentagent 102 to infuse into the porous ceramic proppant particulates 106.In one or more exemplary embodiments, the chemical treatment agent 102can be infused into the porous ceramic particulates 106 using amicrowave infusion process. A suitable microwave infusion process isdisclosed in U.S. patent application Ser. No. 14/813,452, which isincorporated by reference herein in its entirety.

According to several exemplary embodiments, the chemically infusedcoated porous ceramic proppant is prepared according to a one stepprocess. According to the one step process, the porous ceramic proppantparticulates 106 are infused with a chemical treatment agent 102 usingthe thermal infusion process described above and coated with asemi-permeable substantially non-degradable polymer coating 104, 204before the resultant heat from the thermal infusion process dissipates.

According to several exemplary embodiments, the coated proppantparticulates 100, 200 can be prepared according to any suitable process.For example, a chemical treatment agent 102 can be coated onto and/orcontacted with a proppant particulate 106 to produce a chemicaltreatment agent containing proppant particulate. The chemical treatmentagent containing proppant particulate can be coated with asemi-permeable substantially non-degradable polymer, a degradablepolymer, and/or a self-polishing polymer 104, 204. In several exemplaryembodiments, additional chemical treatment agent 102 can be mixed withthe semi-permeable substantially non-degradable polymer, the degradablepolymer, and/or the self-polishing polymer 104, 204 prior to, during, orafter coating onto the proppant particulate 106. In other exemplaryembodiments, the chemical treatment agent 102 is infused into any porousspaces of the proppant particulate 106 as disclosed herein prior tocoating by the chemical treatment agent 102, the semi-permeablesubstantially non-degradable polymer, the degradable polymer, and/or theself-polishing polymer 104, 204. The coated proppant particulates 100,200 can be prepared as disclosed herein without the use of a solvent.

According to several exemplary embodiments, the encapsulated proppantparticulates 300, 400, 500 are prepared according to a three-stepprocess. In the first step, a chemical treatment agent 102 is infusedinto the porous ceramic proppant particulates 106. In the second step,the infused porous ceramic proppant particulates 106 are coated with asemi-permeable substantially non-degradable polymer coating 104 toprovide a coated proppant particulate. In several exemplary embodiments,the chemical treatment agent 102 is infused into the porous ceramicproppant particulates 106 by vacuum infusion. In other exemplaryembodiments, the chemical treatment agent 102 is infused into the porousceramic proppant particulates 106 using a thermal infusion processwhereby the porous ceramic proppant particulates 106 are heated andwetted with a solution containing the chemical treatment agent 102. Asthe porous ceramic proppant particulates 106 cool, capillary actioncauses the chemical treatment agent 102 to infuse into the porousceramic proppant particulates 106. In one or more exemplary embodiments,the chemical treatment agent 102 can be infused into the porous ceramicparticulates 106 using a microwave infusion process. A suitablemicrowave infusion process is disclosed in U.S. patent application Ser.No. 14/813,452, which is incorporated by reference herein in itsentirety. In the third step, the degradable shell 302 can be coated ontothe proppant particulate 106 containing the chemical treatment agent 102to provide the encapsulated proppant 300, 400, 500.

According to several exemplary embodiments, the encapsulated proppant300, 400, 500 is prepared according to a two-step process. In the firststep, the porous ceramic proppant particulates 106 are infused with achemical treatment agent 102 using the thermal infusion process ormicrowave infusion process described above and coated with asemi-permeable substantially non-degradable polymer coating before theresultant heat from the thermal infusion or microwave infusion processdissipates. In the second step, the degradable shell 302 can be coatedonto the proppant particulate 106 containing the chemical treatmentagent 102 to provide the encapsulated proppant 300, 400, 500.

According to several exemplary embodiments, the encapsulated proppantparticulates 300, 400, 500 can be prepared according to any suitableprocess. For example, the chemical treatment agent 102 can be coatedonto and/or contacted with a proppant particulate 106 to produce achemical treatment agent containing proppant particulate. In producingthe encapsulated proppant 300, 400, 500, the chemical treatment agentcontaining proppant particulate can be coated with a semi-permeablesubstantially non-degradable polymer, a degradable polymer, and/or aself-polishing polymer 104. In several exemplary embodiments, additionalchemical treatment agent 102 can be mixed with the semi-permeablesubstantially non-degradable polymer, the degradable polymer, and/or theself-polishing polymer 104 prior to, during, or after coating onto theproppant particulate 106. In other exemplary embodiments, the chemicaltreatment agent 102 is infused into any porous spaces of the proppantparticulate 106 as disclosed herein prior to coating by the chemicaltreatment agent 102, the semi-permeable substantially non-degradablepolymer, the degradable polymer, and/or the self-polishing polymer 104.In one or more exemplary embodiments (not shown), the chemical treatmentagent 102 can be mixed with the degradable shell 302 prior to, during,or after coating the degradable shell 302 directly or indirectly ontothe proppant particulate 106. The chemical treatment agent 102 can beincorporated into the encapsulated proppant 300, 400, 500, in any manneras disclosed herein without the use of a solvent.

According to several exemplary embodiments, a composite ceramic proppantcomposition for use in hydraulic fracturing is produced. According toseveral exemplary embodiments, a composite ceramic proppant compositionfor use in a frac-pack is produced. According to several exemplaryembodiments, a composite ceramic proppant composition for use in agravel-pack is produced. According to several exemplary embodiments, thecomposite ceramic proppant composition includes porous ceramic proppantparticulates 106 infused with a chemical treatment agent 102 without theuse of a solvent. Furthermore, according to several exemplaryembodiments, the infused porous ceramic proppant particulates 106 arecoated with a semi-permeable substantially non-degradable polymercoating 104, 204. According to several other exemplary embodiments, theinfused porous ceramic proppant particulates 106 are coated with adegradable polymer 104, 204. According to several other exemplaryembodiments, the infused porous ceramic proppant particulates 106 arecoated with a self-polishing polymer 104, 204.

According to several exemplary embodiments, another composite ceramicproppant composition for use in hydraulic fracturing is produced.According to several exemplary embodiments, the composite ceramicproppant composition uncoated sand and sand coated with and/or attachedto a chemical treatment agent without the use of a solvent. Furthermore,according to several exemplary embodiments, the chemical treatment agentcontaining sand is coated with a semi-permeable substantiallynon-degradable polymer 104, 204. According to several other exemplaryembodiments, the chemical treatment agent containing sand is coated witha degradable polymer 104, 204. According to several other exemplaryembodiments, the chemical treatment agent containing sand is coated witha self-polishing polymer 104, 204.

According to several exemplary embodiments, the chemical treatment agent102 is infused into the porous ceramic proppant particulates 106 withoutthe use of a solvent by melting, thawing, heating, softening, or warmingthe chemical treatment agent 102 to a sufficiently low viscosity toallow infusion into the porous ceramic proppant particulates 106. Inseveral exemplary embodiments, a sufficiently low viscosity to allowinfusion into the porous ceramic proppant particulate 106 is from about1000-10,000 centipoise (cps), from about 1000-5,000 cps, or from about1000-2500 cps.

According to several exemplary embodiments, after the chemical treatmentagent 102 is melted to a sufficiently low viscosity to allow infusioninto the porous ceramic proppant particulates 106, the melted chemicaltreatment agent 102 is infused into the porous ceramic proppantparticulates 106 using the infusion methods described above.

According to several exemplary embodiments, a composite proppantcomposition for use in hydraulic fracturing is produced. According toseveral exemplary embodiments, the composite proppant compositionincludes one or more of the coated proppants 100, 200 and/or theencapsulated proppants 300, 400, 500 as disclosed herein. The compositeproppant composition can include the coated proppants 100, 200 and/orthe encapsulated proppants 300, 400, 500 in any suitable amounts. In oneor more exemplary embodiments, the composite proppant composition caninclude at least about 1 wt %, at least about 2 wt %, at least about 5wt %, at least about 10 wt %, at least about 20 wt %, at least about 30wt %, at least about 40 wt %, at least about 50 wt %, at least about 60wt %, at least about 70 wt %, at least about 80 wt %, at least about 90wt %, at least about 95 wt %, at least about 99 wt %, or 100 wt % of thecoated proppants 100, 200 and/or the encapsulated proppants 300, 400,500 based on the total weight of the composite proppant composition. Inone or more exemplary embodiments, the composite ceramic proppantcomposition can have a coated proppant 100, 200 and/or encapsulatedproppant 300, 400, 500 concentration of about 1 wt %, about 2 wt %,about 5 wt %, about 10 wt %, about 20 wt %, or about 30 wt % to about 40wt %, about 50 wt %, about 60 wt %, about 70 wt %, about 80 wt %, about90 wt %, about 95 wt %, or about 99 wt % or more.

According to several exemplary embodiments, a method of fracturing asubterranean formation includes injecting a hydraulic fluid into thesubterranean formation at a rate and pressure sufficient to open afracture therein, and a fluid containing a proppant compositionincluding one or more of the coated proppants 100, 200 and/or theencapsulated proppants 300, 400, 500 as disclosed herein is injectedinto the fracture to prop the fracture in an open condition.

The coated proppants 100, 200 and/or the encapsulated proppants 300,400, 500 can be included in a frac-pack or gravel-pack, according toseveral exemplary embodiments. In frac-pack or gravel-pack operations,the coated proppants 100, 200 and/or the encapsulated proppants 300,400, 500 are placed in an annular space between a well casing and aninterior screen or liner in a cased-hole frac-pack or gravel-pack,and/or in an annular space in the wellbore outside a screen or liner inopen-hole fracturing, frac-packing, or gravel-packing operations. Packmaterials are primarily used to filter out solids being produced alongwith the formation fluids in oil and gas well production operations.This filtration assists in preventing these sand or other particles frombeing produced with the desired fluids into the borehole and to thesurface. Such undesired particles might otherwise damage well andsurface tubulars and complicate fluid separation procedures due to theerosive nature of such particles as the well fluids are flowing.

The frac-pack and/or gravel-pack can include the coated proppants 100,200 and/or the encapsulated proppants 300, 400, 500 in any suitableamounts. In one or more exemplary embodiments, the frac-pack and/orgravel-pack can include at least about 1 wt %, at least about 2 wt %, atleast about 5 wt %, at least about 10 wt %, at least about 20 wt %, atleast about 30 wt %, at least about 40 wt %, at least about 50 wt %, atleast about 60 wt %, at least about 70 wt %, at least about 80 wt %, atleast about 90 wt %, at least about 95 wt %, at least about 99 wt %, or100 wt % the coated proppant 100, 200 and/or the encapsulated proppant300, 400, 500.

FIG. 8 depicts a perspective view of an illustrative prepack screenassembly 800 containing a proppant pack 810 containing the coatedproppant 100, 200 and/or the encapsulated proppant 300, 400, 500. Theproppant pack 810 can include the coated proppant 100, 200 and/or theencapsulated proppant 300, 400, 500 in any suitable amounts. In one ormore exemplary embodiments, the proppant pack 810 can include at leastabout 1 wt %, at least about 2 wt %, at least about 5 wt %, at leastabout 10 wt %, at least about 20 wt %, at least about 30 wt %, at leastabout 40 wt %, at least about 50 wt %, at least about 60 wt %, at leastabout 70 wt %, at least about 80 wt %, at least about 90 wt %, at leastabout 95 wt %, at least about 99 wt %, or 100 wt % the coated proppant100, 200 and/or the encapsulated proppant 300, 400, 500.

As shown in FIG. 8, the prepack screen assembly 800 can include atubular 802 having a perforated section 804. At least a portion of theperforated section 804 can be at least partially surrounded by a screen806. For example, the screen 806 can be circumferentially disposed aboutthe perforated section 804 and axially aligned with tubular 802. Anannulus 808 can be formed between the tubular 802 and the screen 806.The proppant pack 810 can be disposed between the tubular 802 and thescreen 806, in the annulus 808. A plurality of longitudinally arrangedrods 812 can be disposed about the proppant pack 810 such that thescreen 806 is at least partially offset from the proppant pack 810. Therods 812 can be spaced apart from one another and arranged coaxiallywith the tubular 802. The screen 806 can be wrapped around the rods 812and welded to the tubular 802 via welds 814. The tubular 802 can includea threaded portion 816 on at least one end thereof for connecting theprepack screen assembly 800 to production tubing (not shown), forexample. FIG. 9 depicts a cross-sectional view of the prepack screentaken along line 8-8 of FIG. 8. Examples of prepack screen assembliescan be found in U.S. Pat. Nos. 4,487,259 and 5,293,935, the entiredisclosures of which are incorporated herein by reference.

The proppant pack 810 can be fused together and/or consolidated. Theproppant pack 810 can be consolidated before, during, or after inclusionof the proppant particulates in the annulus 808. For example, loose,unconsolidated resin-coated proppant particulates can be introduced tothe annulus 808 of the prepack screen assembly 800. After introductionof the coated proppant 100, 200 and/or the encapsulated proppant 300,400, 500 to the annulus 808, a reactive crosslinker can contact theproppant 100, 200 and/or the encapsulated proppant 300, 400, 500 toconsolidate the proppant pack 810. After completion of the prepackscreen assembly 800 at the surface, the pre-pack assembly 800 can belowered downhole to a desired depth.

According to several exemplary embodiments, the coated proppant 100, 200and/or the encapsulated proppant 300, 400, 500 disclosed herein can beplaced into any production tubing, such as a riser in order to deliverthe chemical treatment agents 102 to any downstream tubing and/orequipment. According to several exemplary embodiments, the coatedproppant 100, 200 and/or the encapsulated proppant 300, 400, 500 can beplaced into any pipeline or process apparatus, such as a heat exchanger,in order to deliver chemical treatment agents 102 to a pipeline or anydownstream process tubing and/or equipment. The coated proppant 100, 200and/or the encapsulated proppant 300, 400, 500 can be placed in theproduction tubing, pipelines, and/or process tubing in any suitablemanner. In one or more exemplary embodiments, the coated proppant 100,200 and/or the encapsulated proppant 300, 400, 500 can be placed orcontained in a removeable canister that can then be placed into theproduction tubing, pipelines, and/or process tubing, such as, forexample, upstream and proximate to a pump or compressor.

FIG. 10 depicts a cross-sectional side view of an assembly 1000 having acanister 1002 placed within a tubular 1112. The canister 1002 caninclude a proppant pack 1004 containing the coated proppant 100, 200and/or the encapsulated proppant 300, 400, 500. The canister 1002 canhave any suitable size and shape. For example, the canister 1002 canhave a size and shape corresponding to a size and shape of the tubular1112. The tubular 1112 can be a component of, attached to, or otherwisein fluid communication with, a heat exchanger, a tubular reactor, asubsea riser, a pipeline, a pump, or any other suitable processequipment. As shown in FIG. 10, the canister 1002 can have a cylindricalbody 1006 having an open first end 1008 and an open second end 1010 topermit fluid flow from the first end to the second end. At least aportion of the cylindrical body 1006 can be attached in any suitablemanner to an inner wall or surface of the tubular 1112 for securing thecanister 1002 to the tubular 1112. For example, the body 1006 caninclude a threaded section (not shown) that is capable of mating with acorresponding threaded section (not shown) located on or inside thetubular 1112.

FIG. 11 depicts a cross-sectional end view of the canister 1002. Theproppant pack 1004 can fill an entire cross section of an inner volumeof the body 1006 and/or the canister 1002. In one or more exemplary,embodiments, the proppant pack 1004 at least partially fills the innervolume of the body 1006 of the canister 1002. The proppant pack 1004 canfill at least 10 vol %, at least 25 vol %, at least 50 vol %, at least75 vol %, at least 90 vol %, at least 95 vol %, or at least 99 vol % orabout 100 vol % of the inner volume of the body 1006. In one or moreexemplary embodiments, the proppant pack 1004 can occupy from about 10vol % to about 90 vol %, from about 20 vol % to about 80 vol %, or fromabout 30 vol % to about 70 vol % of the inner volume of the body 1006.The proppant pack 1004 can have any suitable density of the coatedproppant 100, 200 and/or the encapsulated proppant 300, 400, 500. Forexample, the amount of coated proppant 100, 200 and/or the encapsulatedproppant 300, 400, 500 in the proppant pack 1004 can be selected topermit any desirable rate of fluid flow from the first end 1008 to thesecond end 1010. FIG. 12 depicts a perspective view of the canister 1002having a cutaway section 1200 showing the proppant pack 1004. Theproppant pack can be at least partially contained within the body 1006by fluid permeable screens 1202 with a first screen 1202 locatedproximate the first end 1008 and a second screen (not shown) locatedproximate the second end 1010. The screens 1202 can have anyconfiguration or design suitable for permitting fluid flow through inand out of the canister 1002 and blocking proppant flow from thecanister 1002.

The following examples are illustrative of the compositions and methodsdiscussed above.

EXAMPLES

The examples following below were carried out using exemplary materialsin order to determine the elution rate of DTPMP (diethylenetriaminepenta(methylene phosphonic acid)), a corrosion and scale inhibitor, fromporous proppant infused with DTPMP and coated with various polymers andcompared to uncoated porous proppant infused with DTPMP. These examplesare meant to be illustrative of exemplary embodiments of the presentinvention and are not intended to be exhaustive.

Example 1

Four 500 gram batches of 20/40 CARBO UltraLite, an ultra-lightweightceramic proppant having an ASG of 2.71 and having a porosity of 20-25%that is commercially available from CARBO Ceramics, Inc., were eachinfused with a diethylenetriamine penta(methylene phosphonic acid)(“DTPMP”) solution having a solids content of 41%, which is commerciallyavailable from Riteks, Inc., and were then coated with a semi-permeablesubstantially non-degradable polymer in a two-step process as describedbelow.

Each batch of proppant was heated in an oven set to 482° F. (250° C.)for approximately one hour. The heated batches of proppant were thenremoved from the oven and allowed to cool until they reached atemperature of between 430-440° F. as monitored by a thermocouple. Oncethe proppant batches reached the desired temperature, 64.2 grams of theDTPMP solution was added to each batch and allowed to infuse into theproppant particulates for approximately three minutes, such that theDTPMP constituted 5% by weight of the infused proppant. After theproppant particulates were infused with DTPMP, each batch was coatedwith a semi-permeable substantially non-degradable polymer.

The Batch 1 proppant was coated according to the following procedurewith a phenol formaldehyde standard reactivity resin that iscommercially available from Plastics Engineering Company under the tradename Plenco 14870. Compared to the other phenol formaldehyde resinsdiscussed below, the Plenco 14870 resin had a relatively low viscosityof about 1100 cps at 150° C. After the coating procedure, the Batch 1proppant included 2% by weight of the polymeric coating.

The Batch 1 proppant was placed in a heated mixing bowl and wasmonitored with a thermocouple until the proppant reached a temperatureof between 410-420° F. When the proppant reached the desiredtemperature, 8.08 grams of the phenol formaldehyde resin was added tothe proppant and allowed to melt and spread over the proppant forapproximately 45 seconds. Next, 2.63 grams of a 40%hexamethylenetetramine (which is also known as and will be referred toherein as “hexamine”), solution, and which is commercially availablefrom The Chemical Company, was added to crosslink and cure the phenolformaldehyde resin and was allowed to mix for 1 minute and 25 seconds.Finally, 1.2 grams of a 50-60% cocoamidopropyl hydroxysultainesurfactant, which is commercially available from The LubrizolCorporation under the trade name “Chembetaine™ CAS”, was added andallowed to mix for 1 minute.

The Batch 2 proppant was coated according to the following procedurewith a phenol formaldehyde highly reactive, high viscosity polymer resinthat is commercially available from Plastics Engineering Company underthe trade name Plenco 14750. Compared to the other phenol formaldehyderesins discussed above and below, the Plenco 14750 resin had arelatively high viscosity of about 34,900 cps at 150° C. After thecoating procedure, the Batch 2 proppant included 2% by weight of thepolymeric coating.

The Batch 2 proppant was placed in a heated mixing bowl and wasmonitored with a thermocouple until the proppant reached a temperatureof between 410-420° F. When the proppant reached the desiredtemperature, 8.08 grams of the phenol formaldehyde resin was added tothe proppant and allowed to melt and spread over the proppant forapproximately 45 seconds. Next, 2.63 grams of a 40% hexamine solution,which is commercially available from The Chemical Company, was added tocrosslink and cure the phenol formaldehyde resin and was allowed to mixfor 1 minute and 25 seconds. Finally, 1.2 grams of a 50-60%cocoamidopropyl hydroxysultaine surfactant, which is commerciallyavailable from The Lubrizol Corporation under the trade name“Chembetaine™ CAS”, was added and allowed to mix for 1 minute.

The Batch 3 proppant was coated according to the following procedurewith the phenol formaldehyde highly reactive, high viscosity polymerresin mentioned above that is commercially available from PlasticsEngineering Company under the trade name Plenco 14750. As discussedabove, the Plenco 14750 resin had a relatively high viscosity of about34,900 cps at 150° C. After the coating procedure, the Batch 3 proppantincluded 4% by weight of the polymeric coating.

The Batch 3 proppant was placed in a heated mixing bowl and wasmonitored with a thermocouple until the proppant reached a temperatureof between 410-420° F. When the proppant reached the desiredtemperature, 17.61 grams of the phenol formaldehyde resin was added tothe proppant and allowed to melt and spread over the proppant forapproximately 45 seconds. Next, 5.72 grams of a 40% hexamine solution,which is commercially available from The Chemical Company, was added tocrosslink and cure the phenol formaldehyde resin and was allowed to mixfor 1 minute and 25 seconds. Finally, 1.2 grams of a 50-60%cocoamidopropyl hydroxysultaine surfactant, which is commerciallyavailable from The Lubrizol Corporation under the trade name“Chembetaine™ CAS”, was added and allowed to mix for 1 minute.

The Batch 4 proppant was coated according to the following procedurewith a polyurethane polymer that is made by reacting a polyisocyanateresin with a curing agent both of which are commercially available fromAir Products, Inc. under the trade names ANCAREZ® ISO HDiT and AMICURE®IC221, respectively. After the coating procedure, the Batch 4 proppantincluded 4% by weight of the polyurethane polymeric coating.

The Batch 4 proppant was placed in a mixing bowl that was maintained atroom temperature. At room temperature, 13.5 grams of the curing agentAMICURE® IC221 was added to the proppant batch and mixed for one minute.After one minute, 7.2 grams of the ANCAREZ® ISO HDiT polyisocyanateresin was added to the proppant batch and mixed with the proppant forapproximately 5 minutes.

A fifth proppant batch was then prepared that included 1000 grams of20/40 CARBO UltraLite ceramic proppant. The Batch 5 proppant was infusedwith DTPMP and coated in a one-step thermal infusion process with aphenol formaldehyde highly reactive, low viscosity polymer resin that iscommercially available from Plastics Engineering Company under the tradename Plenco 14862. Compared to the other phenol formaldehyde resinsdiscussed above and below, the Plenco 14862 resin had a relatively lowviscosity of about 1080 cps at 150° C. After the one-step thermalinfusion process, the Batch 5 proppant included 2% by weight of thepolymeric coating.

The Batch 5 ceramic proppant was heated in an oven set to 482° F. (250°C.) for approximately one hour. The heated batch of proppant was thenremoved from the oven and allowed to cool until it reached a temperatureof between 430-440° F. as monitored by a thermocouple. Once the proppantbatch reached the desired temperature, 128.4 grams of the DTPMP solutionwas added to the batch and allowed to infuse into the proppantparticulates for approximately 5 seconds, such that the DTPMPconstituted 5% by weight of the infused proppant. After 5 seconds hadelapsed, 17.35 grams of the phenol formaldehyde, high reactivity, lowviscosity polymer resin (Plenco 14862) was added to the proppant batch.After another 5 seconds had elapsed, 5.64 grams of a 40% hexaminesolution, which is commercially available from The Chemical Company, wasadded to crosslink and cure the phenol formaldehyde resin and wasallowed to mix for 10 minutes and 15 seconds. Finally, 1.2 grams of a50-60% cocoamidopropyl hydroxysultaine surfactant, which is commerciallyavailable from The Lubrizol Corporation under the trade name“Chembetaine™ CAS”, was added and allowed to mix for another 30 seconds.

Finally, a sixth proppant batch was prepared as a control. The Batch 6control proppant batch, included 1000 grams of 20/40 CARBO UltraLiteceramic proppant and was infused with DTPMP but did not include apolymeric coating.

The Batch 6 ceramic proppant was heated in an oven set to 482° F. (250°C.) for approximately one hour. The heated batch of proppant was thenremoved from the oven and allowed to cool until it reached a temperatureof between 430-440° F. as monitored by a thermocouple. Once the proppantbatch reached the desired temperature, 241.8 grams of the DTPMP solutionwas added to the batch and allowed to infuse into the proppantparticulates for approximately 3 minutes, such that the DTPMPconstituted 9% by weight of the infused proppant.

Table 1 below represents the 6 batches prepared for Example 1.

TABLE 1 Example 1 Batches Batch Number Infusant/Polymer Coating Batch 15% by weight DTPMP, 2% by weight phenol formaldehyde, standardreactivity, low viscosity (Plenco 14870) Batch 2 5% by weight DTPMP, 2%by weight phenol formaldehyde, high reactivity, high viscosity (Plenco14750) Batch 3 5% by weight DTPMP, 4% by weight phenol formaldehyde,high reactivity, high viscosity (Plenco 14750) Batch 4 5% by weightDTPMP, 4% by weight polyurethane Batch 5 5% by weight DTPMP, 2% byweight phenol formaldehyde, high reactivity, low viscosity (Plenco14862) Batch 6 9% by weight DTPMP, no coating

Proppant Batches 1-6 were then placed in a seawater eluent for one hour.The seawater eluent was prepared according to the ASTM D1141-98(2013)procedure and had the composition shown below in Table 2.

TABLE 2 ION CONC. ION & SALT (mg/L) K⁺ as KCl 403.0 Mg²⁺ as MgCl₂•6H₂O657.0 Na⁺ as NaCl 10025.6 HCO₃ ⁻ as NaHCO₃ 159.0 Na⁺ as NaHCO₃ 59.9 SO₄²⁻ as Fe₂SO₄•7H₂O 0.0 SO₄ ²⁻ as Na₂SO₄•10H₂O 1308.0 Na⁺ as Na₂SO₄•10H₂O626.1 Ca²⁺ as CaCl₂•2H₂O 329.0 Sr²⁺ as SrCl₂•6H₂O 7.0 Ba²⁺ as BaCl₂•2H₂O0.0 Fe(II) as FeCl₂•4H₂O 0.0 Fe(II) as FeSO₄•7H₂O 0.0 CH₃COO⁻ asCH₃COONa•3H₂O 1.0 Na⁺ as CH3COONa 0.4 Total SO₄ ²⁻ 1308.0 Total Na⁺10712.0 Cl⁻ from analysis (mg/L) = 18330.0 Cl⁻ from calculation (mg/L) =18330.0 Error (%) = 0.00% Total Salt Weight (mg/L) = 37591 SaltConcentration (%) = 3.76%

After one hour, the eluent was tested for the amount of DTPMP (in partsper million, ppm) present. For each of proppant Batches 1-5, the eluentwas subsequently tested for the presence of DTPMP at 2, 3, 6, 25, 27.5,29.5, and 97.5 hours, respectively. For proppant Batch 1, the eluent wasadditionally tested for the presence of DTPMP at 100, 102, 104.5 and120.5 hours. For Batch 6, the eluent was subsequently tested for thepresence of DTPMP at 2, 3, 4, 5, 21, 22, 23, 24, 26, 27, 28, 29, 44, 47,49, 53, 70 and 74 hours.

The amount of DTPMP in ppm detected in the eluent was plotted as afunction of time to obtain the elution profile curves shown in FIG. 13.In FIG. 13, a line has been drawn at 6 ppm which represents the minimumeffective concentration of DTPMP as a corrosion and scale inhibitor. Byplotting the amount of detected DTPMP in the eluent versus time forproppant Batches 1-6 and comparing these results with the 6 ppm line,the length of time a particular proppant batch elutes an effectiveamount of DTPMP can be determined.

FIG. 13 clearly shows that proppant Batches 1-5 which included asemi-permeable substantially non-degradable polymeric coating eluted aneffective amount of DTPMP for a longer period of time compared toproppant Batch 6 which did not include a semi-permeable substantiallynon-degradable polymeric coating. FIG. 13 also clearly shows that forthe three proppant batches that were infused with 5% by weight of DTPMPand coated with 2% by weight of phenol formaldehyde according to thetwo-step process, namely proppant Batches 1-3, the lower the viscosityof the resin used to make the phenol formaldehyde polymeric coating, thelonger the period of time in which an effective amount of DTPMP waseluted. In addition, FIG. 13 shows that when phenol formaldehyde resinshaving relatively low viscosity are used to prepare the polymericcoating, the proppant coated according to the two-step process (Batch 1)eluted an effective amount of DTPMP for a longer period of time comparedto proppant coated according to the one-step process (Batch 5). Finally,FIG. 13 shows that for the three proppant batches that were infused with5% by weight of DTPMP and coated with 2% or 4% by weight of phenolformaldehyde according to the two-step process, namely proppant Batches1-3, an effective amount of DTPMP was eluted for a longer period of timecompared to proppant that was infused with 5% by weight of DTPMP andcoated with 2% by weight of polyurethane according to the two-stepprocess.

Example 2

Three 1000 pound plant batches of 20/40 CARBO UltraLite, referred tobelow as Batches 7-9, were infused with the DTPMP solution mentionedabove in Example 1 and were then coated according to the followingprocedure with a phenol formaldehyde standard reactivity resin that iscommercially available from Plastics Engineering Company under the tradename Plenco 14941. Compared to the other phenol formaldehyde resinsdiscussed above, the Plenco 14941 resin had a relatively mediumviscosity of about 1850 cps at 150° C.

Each of Batches 7-9 were infused with 183.6 pounds of the DTPMPsolution, such that the DTPMP constituted 7% by weight of the infusedproppant. The proppant of Batches 7-9 was then coated with the phenolformaldehyde standard reactivity, medium viscosity polymer resin (Plenco14941), in a two-step process. After the two-step process, the Batch 7proppant included 0.5% by weight of the polymeric coating, the Batch 8proppant included 1.0% by weight of the polymeric coating and the Batch9 proppant included 2.0% by weight of the polymeric coating.

After the proppant particulates were infused with 7% DTPMP, each batchwas coated with a different amount of the same semi-permeablesubstantially non-degradable polymer. The Batch 7 proppant was heated to415° F. When the proppant reached the desired temperature, 6.6 pounds ofthe phenol formaldehyde, standard reactivity, medium viscosity polymerresin (Plenco 14941) was added to the proppant and allowed to melt andspread over the proppant for approximately 45 seconds. Next, 2.8 poundsof a 30% hexamine solution, and which is commercially available from TheChemical Company, was added to crosslink and cure the phenolformaldehyde resin and was allowed to mix for 25 seconds. Finally, 0.5pound of a 50-60% cocoamidopropyl hydroxysultaine surfactant, which iscommercially available from The Lubrizol Corporation under the tradename “Chembetaine™ CAS” was added and allowed to mix.

The Batch 8 proppant was heated to 415° F. When the proppant reached thedesired temperature, 12.3 pounds of the phenol formaldehyde, standardreactivity, medium viscosity polymer resin (Plenco 14941) was added tothe proppant and allowed to melt and spread over the proppant forapproximately 45 seconds. Next, 5.2 pounds of a 30% hexamine solution,and which is commercially available from The Chemical Company, was addedto crosslink and cure the phenol formaldehyde resin and was allowed tomix for 25 seconds. Finally, 0.5 pound of a 50-60% cocoamidopropylhydroxysultaine surfactant, which is commercially available from TheLubrizol Corporation under the trade name “Chembetaine™ CAS” was addedand allowed to mix.

The Batch 9 proppant was heated to 415° F. When the proppant reached thedesired temperature, 22.7 pounds of the phenol formaldehyde, standardreactivity, medium viscosity polymer resin (Plenco 14941) was added tothe proppant and allowed to melt and spread over the proppant forapproximately 45 seconds. Next, 9.7 pounds of a 30% hexamine solution,and which is commercially available from The Chemical Company, was addedto crosslink and cure the phenol formaldehyde resin and was allowed tomix for 25 seconds. Finally, 0.5 pounds of a 50-60% cocoamidopropylhydroxysultaine surfactant, which is commercially available from TheLubrizol Corporation under the trade name “Chembetaine™ CAS” was addedand allowed to mix.

Proppant Batches 7-9 of Example 2 were compared with proppant Batches 1,2 and 6 from Example 1, as indicated in Table 3 below.

TABLE 3 Example 2 Batches Batch Number Infusant/Polymer Coating Batch 15% by weight DTPMP, 2% by weight phenol (from Example 1) formaldehyde,standard reactivity, low viscosity (Plenco 14870) Batch 2 5% by weightDTPMP, 2% by weight phenol (from Example 1) formaldehyde, highreactivity, high viscosity (Plenco 14750) Batch 6 9% by weight DTPMP, nocoating (from Example 1) Batch 7 7% by weight DTPMP, 0.5% by weightphenol formaldehyde, standard reactivity, medium viscosity (Plenco14941) Batch 8 7% by weight DTPMP, 1.0% by weight phenol formaldehyde,standard reactivity, medium viscosity (Plenco 14941) Batch 9 7% byweight DTPMP, 2.0% by weight phenol formaldehyde, standard reactivity,medium viscosity (Plenco 14941)

Proppant Batches 7-9 were then placed in a seawater eluent for one hour.The seawater eluent was prepared according to the ASTM D1141-98(2013)procedure and had the composition shown above in Table 2. After onehour, the eluent was tested for the amount of DTPMP present. The eluentwas subsequently tested for the presence of DTPMP at 2, 3, 4, 5, 6, 7,8, 25, 29, 33, and 48.5 hours, respectively. For proppant Batch 9, theeluent was additionally tested for the presence of DTPMP at 53.5 and55.5 hours. For Batches 1, 2 and 6, the eluent was subsequently testedfor the presence of DTPMP as described above in Example 1.

The amount of DTPMP in ppm detected in the eluent for Batches 7-9 wasplotted with the data from Batches 1, 2 and 6 from Example 1 as afunction of time to obtain the elution profile curves shown in FIG. 14.In FIG. 14, a line has been drawn at 6 ppm which represents the minimumeffective concentration of DTPMP as a corrosion and scale inhibitor. Byplotting the amount of detected DTPMP in the eluent versus time forproppant Batches 1-2 and 6-9 and comparing these results with the 6 ppmline, the length of time a particular proppant batch elutes an effectiveamount of DTPMP can be determined.

FIG. 14 clearly shows that proppant Batches 7-9 which included asemi-permeable substantially non-degradable polymeric coating eluted aneffective amount of DTPMP for a longer period of time compared toproppant Batch 6 which did not include a semi-permeable substantiallynon-degradable polymeric coating. In addition, FIG. 14 clearly showsthat for the three proppant batches that were infused with 7% by weightof DTPMP and coated with 0.5%, 1.0% and 2.0% by weight of phenolformaldehyde according to the two-step process, namely proppant Batches7-9, an effective amount of DTPMP was eluted for a longer period of timethe higher the percent by weight of the phenol formaldehyde polymericcoating.

Example 3

A 500 gram batch of 20/40 CARBO UltraLite, referred to below as Batch 10was infused with 64.2 grams of the DTPMP solution mentioned above inExample 1, such that the DTPMP constituted 5% by weight of the infusedproppant and was then coated with polylactic acid such that the finalproduct included 2% by weight of the polylactic acid coating in atwo-step thermal process. Polylactic acid is a degradable polymericcoating that is commercially available from Danimer under the trade nameof “92938”. 500 grams of the 20/40 CARBO UltraLite was heated in an ovenset at 250° C. for one hour. 64.2 grams of the DTPMP solution was addedto the heated proppant and allowed to mix for 3 minutes. The infusedproppant was then heated to 193° C. and 51.0 grams of the polylacticacid polymer resin was added to the batch and allowed to mix forapproximately ten minutes.

A 500 gram batch of 20/40 CARBO UltraLite, referred to below as Batch 11was infused with DTPMP and coated with a polyurethane coating accordingto the procedure discussed above, except that 3.6 grams of the AncarezISO HDiT polyisocyanate polymer resin was used to result in a 2% byweight coating of polyurethane.

Proppant Batches 10 and 11 were compared with proppant Batches 1 and 6from Example 1, as indicated in Table 4 below.

TABLE 4 Example 3 Batches Batch Number Infusant/Polymer Coating Batch 15% by weight DTPMP, 2% by weight phenol formaldehyde, standardreactivity, low viscosity (Plenco 14870) Batch 6 5% by weight DTPMP, nocoating Batch 10 5% by weight DTPMP, 2% by weight polylactic acid Batch11 5% by weight DTPMP, 2% by weight polyurethane

Proppant Batches 1, 6, 10 and 11 were then placed in a seawater eluentfor one hour. The seawater eluent was prepared according to the ASTMD1141-98(2013) procedure and had the composition shown above in Table 2.After one hour, the eluent was tested for the amount of DTPMP present.The eluent was subsequently tested for the presence of DTPMP at 2, 3, 4,5, 21, 22, 23, 24, 26, 27, 28, 29, 44, 47, 49, 53, 70 and 74 hours,respectively. For proppant Batch 1, the eluent was additionally testedfor the presence of DTPMP at 93, 98, 165, 173, 189.5, 197.5 and 218hours.

The amount of DTPMP in ppm detected in the eluent was plotted as afunction of time to obtain the elution profile curves shown in FIG. 15.In FIG. 15, a line has been drawn at 6 ppm which represents the minimumeffective concentration of DTPMP as a corrosion and scale inhibitor. Byplotting the amount of detected DTPMP in the eluent versus time forproppant Batches 1, 6, 10 and 11 and comparing these results with the 6ppm line, the length of time a particular proppant batch elutes aneffective amount of DTPMP can be determined.

FIG. 15 clearly shows that proppant Batch 1 which was infused with 5% byweight of DTPMP and coated with 2% by weight of phenol formaldehydeaccording to the two-step process eluted an effective amount of DTPMPfor a longer period of time compared to proppant Batches 10 and 11 whichwere infused with 5% by weight of DTPMP and coated with 2.0% by weightof polylactic acid and polyurethane, respectively. In addition, FIG. 15shows that proppant Batches 10 and 11 which included a degradable and asemi-permeable substantially non-degradable polymeric coating,respectively, eluted an effective amount of DTPMP for a longer period oftime compared to proppant Batch 6 which did not include a semi-permeablesubstantially non-degradable polymeric coating. FIG. 15 also shows thatsubstantially similar results were obtained for proppant Batch 10, thatwas infused with 5% by weight of DTPMP and coated with 2.0% by weight ofpolylactic acid, a degradable polymer and proppant Batch 11 that wasinfused with 5% by weight of DTPMP and coated with 2.0% by weight ofpolyurethane, a semi-permeable substantially non-degradable polymer.

The above results show that infused proppant particulates coated with asemi-permeable substantially non-degradable polymer, like phenolformaldehyde and polyurethane, release effective amounts of chemicaltreatment agents like DTPMP for a longer period of time than typicaldegradable coatings or proppant without any coating at all.

Example 4

The example following below was carried out using exemplary materials inorder to determine the elution rate of DTPMP from coated porous proppantinfused with DTPMP and further coated with various amounts of degradablecoatings and compared to coated porous proppant infused with DTPMP andnot containing a degradable coating.

Three 500 gram batches of 20/40 CARBO UltraLite, an ultra-lightweightceramic proppant having an ASG of 2.71 and having a porosity of 20-25%that is commercially available from CARBO Ceramics Inc., were eachinfused with a diethylenetriamine penta(methylene phosphonic acid)(“DTPMP”) solution having a solids content of 41%, which is commerciallyavailable from Riteks, Inc., and were then coated with a semi-permeablesubstantially non-degradable polymer in a two-step process as describedbelow.

Each batch of proppant was heated in an oven set to 482° F. (250° C.)for approximately one hour. The heated batches of proppant were thenremoved from the oven and allowed to cool until they reached atemperature of between 430-440° F. as monitored by a thermocouple. Oncethe proppant batches reached the desired temperature, 64.2 grams of theDTPMP solution was added to each batch and allowed to infuse into theproppant particulates for approximately three minutes, such that theDTPMP constituted 5% by weight of the infused proppant. After theproppant particulates were infused with DTPMP, each batch was coatedwith a semi-permeable substantially non-degradable polymer.

Each batch of proppant containing the 5% by weight DTPMP was then coatedaccording to the following procedure with a phenol formaldehyde highlyreactive, high viscosity polymer resin that is commercially availablefrom Plastics Engineering Company under the trade name Plenco 14750.Each batch was placed in a heated mixing bowl and was monitored with athermocouple until the proppant reached a temperature of between410-420° F. When the proppant reached the desired temperature, 8.08grams of the phenol formaldehyde resin was added to the proppant andallowed to melt and spread over the proppant for approximately 45seconds. Next, 2.63 grams of a 40% hexamine solution made from a purehexamine powder commercially available from Bossco Industries, Inc., wasadded to crosslink and cure the phenol formaldehyde resin and wasallowed to mix for 1 minute and 25 seconds. After the phenolformaldehyde coating procedures, each batch of proppant included 2% byweight of the polymeric coating.

Only batches 1 and 2 of the proppant containing 2% by weight of thepolymeric coating were subjected to a simultaneous application ofdegradable coating and water quench by applying the hot batches at atemperature of between 250-300° F. to a degradable shell solution,containing approximately 50% polyolefin and approximately 50% water,that is commercially available from Danimer Scientific under the tradename of “MHG-00254.” Batch 1 was subjected to the MHG-00254 solution for2 minutes and batch 2 was subjected to the MHG-00254 solution for 2minutes, until Batch 1 had 2% by weight degradable shell and Batch 2 had4% by weight degradable shell.

Finally, 1.2 grams of a 50-60% cocoamidopropyl hydroxysultainesurfactant, which is commercially available from The LubrizolCorporation under the trade name “Chembetaine™ CAS”, was added to eachbatch and allowed to mix for 1 minute.

Table 5 below represents the 3 batches prepared for this Example 4.

TABLE 5 Example 4 Batches Batch Number Infusant/PolymerCoating/Degradable Shell Batch 1 5% by weight DTPMP, 2% by weight phenolformaldehyde, high reactivity, high viscosity (Plenco 14750), 2% byweight polyolefin shell (MHG-00254) Batch 2 5% by weight DTPMP, 2% byweight phenol formaldehyde, high reactivity, high viscosity (Plenco14750), 4% by weight polyolefin shell (MHG-00254) Batch 3 5% by weightDTPMP, 2% by weight phenol formaldehyde, high reactivity, high viscosity(Plenco 14750)

Proppant Batches 1-6 were then placed in a seawater eluent for one hour.The seawater eluent was prepared according to the ASTM D1141-98(2013)procedure and had the composition shown below in Table 2, above.

After one hour, the eluent was tested for the amount of DTPMP (in partsper million, ppm) present. For Batches 1 and 2, the eluent wassubsequently tested for the presence of DTPMP at 20 minutes, 40 minutes,and 60 minutes. For proppant Batch 3, the eluent was additionally testedfor the presence of DTPMP at 10 minutes, 30 minutes, and 50 minutes.

The amount of DTPMP in ppm detected in the eluent was plotted as afunction of time to obtain the elution profile curves shown in FIG. 16.FIG. 16 clearly shows that proppant Batches 1 and 2, which included thedegradable shell, reduced the rate of initial elution of DTPMP comparedto that of proppant Batch 3, which did not include a degradable shell.FIG. 16 also unexpectedly shows that doubling the amount of degradablecoating (from 2 wt % to 4 wt %) almost tripled the reduction of DTPMPelution (from 19% to 54%, respectively).

Exemplary embodiments of the present disclosure further relate to anyone or more of the following paragraphs:

1. A ceramic proppant composition for use in hydraulic fracturing, thecomposition comprising: non-porous particulates having a permeabilityand a conductivity; porous ceramic particulates wherein the porousceramic particulates are infused with a chemical treatment agent;wherein the composition has a permeability that is at least equal to thepermeability of the non-porous particulates; and wherein the compositionhas a conductivity that is at least about 70% of the conductivity of thenon-porous particulates.

2. The composition according to paragraph 1, wherein at least one of thenon-porous particulates and the porous particulates have an apparentspecific gravity that is less than 3.1 g/cm³.

3. The composition according to paragraph 1, wherein at least one of thenon-porous particulates and the porous ceramic particulates have anapparent specific gravity of from 3.1 to 3.4 g/cm³.

4. The composition according to paragraph 1, wherein at least one of thenon-porous particulates and the porous ceramic particulates has anapparent specific gravity that is greater than 3.4 g/cm³.

5. The composition according to any one of paragraphs 1 to 4, whereinthe composition has a conductivity that is at least equal to theconductivity of the non-porous particulates.

6. The composition according to any one of paragraphs 1 to 5, whereinthe non-porous particulate is selected from the group consisting oflight weight ceramic non-porous proppant, intermediate density ceramicnon-porous proppant and high density ceramic porous proppant.

7. The composition according to any one of paragraphs 1 to 6, whereinthe porous particulate is selected from the group consisting of lightweight ceramic porous proppant, intermediate density ceramic porousproppant and high density ceramic porous proppant.

8. The composition according to any one of paragraphs 1 to 7, whereinthe chemical treatment agent is selected from the group consisting ofscale inhibitors, tracer materials, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, wax inhibitors, asphalteneinhibitors, organic deposition inhibitors, biocides, demulsifiers,defoamers, gel breakers, salt inhibitors, oxygen scavengers, ironsulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, nanoparticle dispersions, surfactants and combinationsthereof.

9. The composition according to paragraph 8, wherein the tracer materialcomprises a chemical tracer.

10. The composition according to paragraph 9, wherein the chemicaltracer comprises a biological marker.

11. The composition according to paragraph 10, wherein the biologicalmarker comprises DNA.

12. The composition according to paragraph 8, wherein the tracermaterial comprises at least one of metallic and non-metallicnanoparticles.

13. The composition according to paragraph 8, wherein the nanoparticledispersions alters wettability of the ceramic proppant composition in ahydraulic fracture environment.

14. The composition according to paragraph 8, wherein the surfactantalters wettability of the ceramic proppant composition in a hydraulicfracture environment.

15. The composition according to any one of paragraphs 1 to 14, whereinthe porous ceramic composition further comprises a degradable coating ora non-degradable coating, and wherein the degradable coating degradesinside the fracture.

16. The composition according to paragraph 15, wherein the degradablecoating is selected from the group consisting of polylactic acid,water-soluble polymers and cross-linkable water-soluble polymers.

17. The composition according to paragraphs 15 or 16, wherein thechemical treatment agent is selected from the group consisting of scaleinhibitors, tracer materials, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, wax inhibitors, asphalteneinhibitors, organic deposition inhibitors, biocides, demulsifiers,defoamers, gel breakers, salt inhibitors, oxygen scavengers, ironsulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, nanoparticle dispersions, surfactants and combinationsthereof.

18. A method of hydraulic fracturing a subterranean formation,comprising: injecting a hydraulic fluid into a subterranean formation ata rate and pressure sufficient to open a fracture therein; and injectinga fluid containing a proppant composition, wherein the proppantcomposition comprises non-porous particulates and porous ceramicparticulates infused with a chemical treatment agent; wherein thenon-porous particulates have a permeability and a conductivity; whereinthe proppant composition has a permeability that is at least equal tothe permeability of the non-porous particulates; and wherein thecomposition has a conductivity that is at least about 70% of theconductivity of the non-porous particulates.

19. The method according to paragraph 18, wherein the non-porousparticulates are selected from the group consisting of light weightceramic non-porous proppant, intermediate density ceramic non-porousproppant and high density ceramic porous proppant and wherein the porousparticulates are selected from the group consisting of light weightceramic porous proppant, intermediate density ceramic non-porousproppant and high density ceramic porous proppant.

20. The method according to paragraphs 18 or 19, wherein the chemicaltreatment agent is selected from the group consisting of tracers, scaleinhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials,corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organicdeposition inhibitors, biocides, demulsifiers, defoamers, gel breakers,salt inhibitors, oxygen scavengers, iron sulfide scavengers, ironscavengers, clay stabilizers, enzymes, biological agents, flocculants,naphthenate inhibitors, carboxylate inhibitors, nanoparticledispersions, surfactants and any other oil field treatment chemical.

21. The method according to paragraph 20, wherein the tracer comprises achemical tracer.

22. The method according to paragraph 21, wherein the chemical tracercomprises a biological marker.

23. The method according to paragraph 22, wherein the chemical tracercomprises DNA.

24. The method according to paragraph 20, wherein the tracer is selectedfrom the group consisting of metallic nano particles and non-metallicnano particles.

25. The method according to paragraph 20, wherein the nanoparticledispersions alter wettability of the ceramic proppant composition in ahydraulic fracture environment.

26. The method according to paragraph 20, wherein the surfactant alterswettability of the ceramic proppant composition in a hydraulic fractureenvironment.

27. The method according to any one of paragraphs 18 to 26, wherein theporous ceramic particulates further comprises a degradable coating or anon-degradable coating and wherein the degradable coating degradesinside the fracture.

28. The method according to paragraph 27, wherein the degradable coatingis selected from the group consisting of polylactic acid, water-solublepolymers and cross-linkable water-soluble polymers.

29. The method according to paragraphs 27 or 28, wherein the chemicaltreatment agent is selected from the group consisting of scaleinhibitors, tracer materials, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, wax inhibitors, asphalteneinhibitors, organic deposition inhibitors, biocides, demulsifiers,defoamers, gel breakers, salt inhibitors, oxygen scavengers, ironsulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, nanoparticle dispersions, surfactants and combinationsthereof.

30. The method according to any one of paragraphs 18 to 29, wherein thecomposition has a conductivity that is at least equal to theconductivity of the non-porous particulates.

31. A method of diagnostic evaluation of a hydraulic fracturingstimulation of a subterranean formation, comprising: injecting ahydraulic fluid into at least one stage of the subterranean formation ata rate and pressure sufficient to open a fracture therein, thesubterranean formation comprising one or more formation fluids and thehydraulic fluid comprising a proppant composition comprising porousparticulates infused with a biological marker; wherein the biologicalmarker separates from the proppant composition continuously over aperiod of time; wherein the biological marker returns to the surfacewith the formation fluids; and wherein the biological marker isrecovered and identified.

32. The method according to paragraph 31, wherein the biological markeris DNA.

33. The method according to paragraphs 31 or 32, wherein the porousparticulate is a porous ceramic proppant.

34. The method according to any one of paragraphs 31 to 33, wherein thebiological marker is encapsulated.

35. The method according to paragraph 32, wherein the DNA comprises aspecific sequence of nitrogenous bases that exhibits thermal stabilityqualities that are compatible with the thermal properties of thesubterranean formation.

36. The method according to paragraph 35, wherein the DNA exhibitsthermal stability at a temperature up to about 186 to 221° F., up toabout 222 to 250° F., or up to about 269 to about 292° F.

37. The method according to any one of paragraphs 31 to 36, wherein thehydraulic fracturing stimulation of the subterranean formation isperformed in a plurality of stages and the proppant composition injectedinto each such stage comprises porous particulates infused with a uniquebiological marker, such that no two stages of the subterranean formationare injected with a proppant composition comprising porous particulatesinfused with the same biological marker.

38. The method according to paragraph 36, further comprising injecting aproppant composition including porous particulates infused with anuniquely identifiable biological marker into different segments of astage of the subterranean formation, such that no two segments of astage of the subterranean formation are injected with proppantcompositions including porous particulates infused with the samebiological marker.

39. The method according to any one of paragraphs 31 to 38, wherein thebiological marker separates from the proppant composition by at leastone of leaching, eluting, diffusing, bleeding, discharging, dissolving,desorbing, draining, seeping, and leaking out of the proppantcomposition.

40. The method according to any one of paragraphs 31 to 39, wherein theformation fluids have an aqueous phase and wherein the biological markerseparates into the aqueous phase of the formation fluids when separatingfrom the porous particulate.

41. The method according to any one of paragraphs 31 to 40, wherein theformation fluids have a hydrocarbon phase and wherein the biologicalmarker separates into the hydrocarbon phase of the formation fluids whenseparating from the porous particulate.

42. The method according to any one of paragraphs 31 to 41, wherein thebiological marker separates from the proppant composition over a periodof up to about one year after placement of the proppant composition inthe subterranean formation.

43. The method according to any one of paragraphs 31 to 42, wherein thebiological marker separates from the proppant composition over a periodof up to about five years after placement of the proppant composition inthe subterranean formation.

44. The method according to any one of paragraphs 31 to 43, wherein thebiological marker separates from the proppant composition over a periodof up to about ten years after placement of the proppant composition inthe subterranean formation.

45. The method according to any one of paragraphs 31 to 44, whereinmultiple uniquely identifiable biological markers from different stagesof the subterranean formation are simultaneously recovered andidentified.

46. The method according to any one of paragraphs 31 to 45, furthercomprising, estimating the relative hydrocarbon or water volumecontribution of a stage or stages of the subterranean formation based onthe relative amounts of uniquely identifiable biological markersrecovered from the stage or stages of the subterranean formation.

47. The method according to any one of paragraphs 31 to 46, furthercomprising, estimating the relative hydrocarbon or water volumecontribution from each segment of a stage of the subterranean formationbased on the amount of uniquely identifiable biological markersrecovered from each segment of a stage of the subterranean formation.

48. The method according to paragraph 34, wherein the biological markeris encapsulated by a polymer.

49. The method according to paragraph 48, wherein the polymer is atleast one member selected from the group consisting of high meltingacrylate-, methacrylate- or styrene-based polymers, block copolymers ofpolylactic-polyglycolic acid, polyglycolics, polylactides, polylacticacid, gelatin, water-soluble polymers, cross-linkable water-solublepolymers, lipids, gels and silicas.

50. The method according to any one of paragraphs 31 to 49, wherein theproppant composition further comprises non-porous particulates andwherein the porous particulates of the proppant composition have aninternal interconnected porosity of from about 5 to about 15% or fromabout 15 to about 35%.

51. The method according to any one of paragraphs 31 to 50, wherein theporous particulates of the proppant composition include a permeablecoating.

52. A proppant composition for use in hydraulic fracturing, thecomposition comprising: porous particulates infused with a biologicalmarker; wherein the porous particulates have an internal interconnectedporosity; and wherein the biological marker separates from the porousparticulates after a period of time.

53. The proppant composition according to paragraph 52, wherein theporous particulates are selected from the group consisting of lightweight porous ceramic proppant, intermediate density porous ceramicproppant and high density porous ceramic proppant.

54. The proppant composition according to paragraphs 52 or 53, whereinthe biological marker is DNA.

55. The proppant composition according to paragraph 54, wherein the DNAcomprises a specific sequence of nitrogenous bases that exhibits thermalstability qualities that are compatible with the thermal properties ofthe subterranean formation.

56. The proppant composition according to paragraphs 54 or 55, whereinthe DNA exhibits thermal stability at a temperature up to about 186 to221° F., up to about 222 to 250° F., or up to about 269 to about 292° F.

57. The proppant composition according to any one of paragraphs 52 to56, wherein the biological marker is encapsulated by a polymer.

58. The proppant composition according to paragraph 57, wherein thepolymer is at least one member selected from the group consisting ofhigh melting acrylate-, methacrylate- or styrene-based polymers, blockcopolymers of polylactic-polyglycolic acid, polyglycolics, polylactides,polylactic acid, gelatin, water-soluble polymers, cross-linkablewater-soluble polymers, lipids, gels and silicas.

59. The proppant composition according to any one of paragraphs 52 to58, wherein the proppant composition further comprises non-porousparticulates and wherein the porous particulates have an internalinterconnected porosity of from about 5-15% or from about 15-35%.

60. The proppant composition according to any one of paragraphs 52 to59, wherein the proppant composition is injected into a hydraulicallycreated fracture in a subterranean formation.

61. The proppant composition according to paragraph 60, wherein thebiological marker separates from the porous particulates over a periodof up to about one year after injection of the proppant composition inthe hydraulically created fracture in the subterranean formation.

62. The proppant composition according to paragraph 60, wherein thebiological marker separates from the porous particulates over a periodof up to about five years after injection of the proppant composition inthe hydraulically created fracture in the subterranean formation.

63. The proppant composition according to paragraph 60, wherein thebiological marker separates from the porous particulates over a periodof up to about ten years after injection of the proppant composition inthe hydraulically created fracture in the subterranean formation.

64. A ceramic proppant composition for use in hydraulic fracturing, thecomposition comprising: porous ceramic particulates; a chemicaltreatment agent infused in the porous ceramic particulates; and asemi-permeable substantially non-degradable polymeric coating.

65. The composition according to paragraph 64, wherein the porousparticulate is selected from the group consisting of light weightceramic porous proppant, intermediate density ceramic porous proppantand high density ceramic porous proppant.

66. The composition according to paragraphs 64 or 65, wherein thechemical treatment agent is selected from the group consisting of scaleinhibitors, tracer materials, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, paraffin inhibitors, waxinhibitors, asphaltene inhibitors, organic deposition inhibitors,biocides, defoamers, gel breakers, salt inhibitors, oxygen scavengers,iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, demulsifiers and combinations thereof.

67. The composition according to paragraph 66, wherein the tracermaterial comprises a chemical tracer selected from the group consistingof dyes, fluorescent materials, metallic nano-particles, non-metallicnano-particles and biological markers.

68. The composition according to paragraph 67, wherein the chemicaltracer comprises DNA.

69. The composition according to any one of paragraphs 64 to 68, furthercomprising non-porous ceramic particulates.

70. The composition according to paragraph 67, wherein the tracermaterial comprises at least one of metallic nano-particles andnon-metallic nano-particles.

71. The composition according to any one of paragraphs 64 to 70, whereinthe semi-permeable substantially non-degradable polymeric coating isselected from the group consisting of phenol formaldehyde, polyurethane,cellulose esters, polyamides, vinyl esters, epoxies and combinationsthereof.

72. A ceramic proppant composition for use in hydraulic fracturing, thecomposition comprising: porous ceramic particulates; and a chemicaltreatment agent infused in the porous ceramic particulates, wherein thechemical treatment agent is infused into the porous ceramic particulateswithout the use of a solvent.

73. The composition according to paragraph 72, further comprisingnon-porous ceramic particulates and wherein the porous ceramicparticulates are selected from the group consisting of light weightceramic porous proppant, intermediate density ceramic porous proppantand high density ceramic porous proppant.

74. The composition according to paragraphs 72 or 73, wherein thechemical treatment agent is selected from the group consisting of scaleinhibitors, tracer materials, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, paraffin inhibitors, waxinhibitors, asphaltene inhibitors, organic deposition inhibitors,biocides, defoamers, gel breakers, salt inhibitors, oxygen scavengers,iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, demulsifiers and combinations thereof.

75. The composition according to paragraph 74, wherein the chemicaltreatment agent comprises at least one of a paraffin inhibitor and a waxinhibitor.

76. The composition according to paragraph 75, wherein the at least oneof a paraffin inhibitor and a wax inhibitor comprises an ethylene vinylacetate copolymer.

77. The composition according to any one of paragraphs 72 to 75, whereinthe porous ceramic particulates further comprise a semi-permeablesubstantially non-degradable polymeric coating.

78. The composition according to paragraph 77, wherein thesemi-permeable substantially non-degradable polymeric coating isselected from the group consisting of phenol formaldehyde, polyurethane,cellulose esters, polyamides, vinyl esters, epoxies and combinationsthereof.

79. The composition according to paragraph 73, wherein the porousceramic particulates further comprise a degradable polymeric coatingselected from the group consisting of polylactic acid, cellulose esters,methyl cellulose and combinations thereof.

80. A method of hydraulically fracturing a subterranean formation,comprising: injecting a hydraulic fluid into a subterranean formation ata rate and pressure sufficient to open a fracture therein; infusingporous ceramic particulates with a chemical treatment agent; coating theinfused porous ceramic particulates with a semi-permeable substantiallynon-degradable polymer; and injecting a fluid containing the coatedinfused porous ceramic particulates into the subterranean formation,wherein the infused chemical treatment agent is released into thesubterranean formation over a period of time.

81. The method according to paragraph 80, wherein the fluid furthercontains non-porous ceramic particulates and wherein the porous ceramicparticulates are selected from the group consisting of light weightceramic porous proppant, intermediate density ceramic non-porousproppant and high density ceramic porous proppant.

82. The method according to paragraphs 80 or 81, wherein the chemicaltreatment agent is selected from the group consisting of tracers, scaleinhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials,corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphalteneinhibitors, organic deposition inhibitors, biocides, defoamers, gelbreakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers,iron scavengers, clay stabilizers, enzymes, biological agents,flocculants, naphthenate inhibitors, carboxylate inhibitors,demulsifiers and combinations thereof.

83. The method according to paragraph 82, wherein the tracer materialcomprises a chemical tracer selected from the group consisting of dyes,fluorescent materials, metallic nano-particles, non-metallicnano-particles and biological markers.

84. The method according to paragraph 83, wherein the chemical tracercomprises DNA.

85. The method according to paragraph 83, wherein the tracer materialcomprises at least one of metallic nano-particles and non-metallicnano-particles.

86. The method according to any one of paragraphs 80 to 85, wherein theporous ceramic particulates are infused with the chemical treatmentagent by at least one of vacuum infusion, thermal infusion, capillaryaction, ribbon blending at room or elevated temperature, microwaveblending and pug mill mixing.

87. The method according to any one of paragraphs 80 to 86, wherein thesemi-permeable substantially non-degradable polymer coating is selectedfrom the group consisting of phenol formaldehyde, polyurethane,cellulose esters, polyamides, vinyl esters, epoxies and combinationsthereof.

88. The method according to any one of paragraphs 80 to 87, wherein thechemical treatment agent is released into the subterranean formation byat least one of leaching, eluting, diffusing, bleeding, discharging,dissolving, desorbing, draining, seeping, and leaking from the porousceramic particulates.

89. The method according to paragraph 88, wherein the chemical treatmentagent is released from the porous ceramic particulates over a period ofup to about ten years after placement of the porous ceramic particulatesin the hydraulically created fracture.

90. The method according to paragraph 89, wherein the chemical treatmentagent is released from the porous ceramic particulates over a period ofup to about five years after placement of the porous ceramicparticulates in the hydraulically created fracture.

91. The method according to paragraph 90, wherein the chemical treatmentagent is released from the porous ceramic particulates over a period ofup to about one year after placement of the porous ceramic particulatesin the hydraulically created fracture.

92. A method of hydraulically fracturing a subterranean formation,comprising: injecting a hydraulic fluid into a subterranean formation ata rate and pressure sufficient to open a fracture therein; infusing aporous ceramic particulates with a chemical treatment agent without theuse of a solvent; and injecting a fluid containing the infused porousceramic particulates into the fracture in the subterranean formation,wherein the infused chemical treatment agent is released into thesubterranean formation over a period of time.

93. The method according to paragraph 92, wherein the chemical treatmentagent is selected from the group consisting of scale inhibitors, tracermaterials, hydrate inhibitors, hydrogen sulfide scavenging materials,corrosion inhibitors, paraffin inhibitors, wax inhibitors, asphalteneinhibitors, organic deposition inhibitors, biocides, defoamers, gelbreakers, salt inhibitors, oxygen scavengers, iron sulfide scavengers,iron scavengers, clay stabilizers, enzymes, biological agents,flocculants, naphthenate inhibitors, carboxylate inhibitors,demulsifiers and combinations thereof.

94. The method according to paragraph 93, wherein the chemical treatmentagent is at least one of a paraffin inhibitor and a wax inhibitor.

95. The method according to paragraph 94, wherein the at least one of aparaffin inhibitor and a wax inhibitor comprises an ethylene vinylacetate copolymer.

96. The method according to paragraph 95, wherein the infused porousceramic particulates are coated with a semi-permeable substantiallynon-degradable polymer selected from the group consisting of phenolformaldehyde, polyurethane, cellulose ester, polyamides, vinyl esters,epoxies and combinations thereof.

97. The method according to paragraph 96, wherein the chemical treatmentagent is released into the subterranean formation by at least one ofleaching, eluting, diffusing, bleeding, discharging, dissolving,desorbing, draining, seeping, and leaking from the infused porousceramic particulates.

98. The method according to paragraph 97, wherein the chemical treatmentagent is released from the infused porous ceramic particulates over aperiod of up to about ten years after placement of the porous ceramicparticulates in the hydraulically created fracture.

99. The method according to paragraph 98, wherein the chemical treatmentagent is released from the infused porous ceramic particulates over aperiod of up to about five years after placement of the porous ceramicparticulates in the hydraulically created fracture.

100. The method according to paragraph 99, wherein the chemicaltreatment agent is released from the infused porous ceramic particulatesover a period of up to about one year after placement of the porousceramic particulates in the hydraulically created fracture.

101. A ceramic proppant composition for use in hydraulic fracturing, thecomposition comprising: porous ceramic particulates; a water-solublechemical treatment agent infused in the porous ceramic particulates; anda coating comprising a hydrocarbon-soluble chemical treatment agent.

102. The composition according to paragraph 101, further comprisingnon-porous ceramic particulates and wherein the porous particulate isselected from the group consisting of light weight ceramic porousproppant, intermediate density ceramic porous proppant and high densityceramic porous proppant.

103. The composition according to paragraph 102, wherein thewater-soluble chemical treatment agent comprises a scale inhibitor andthe hydrocarbon-soluble chemical treatment agent comprises a paraffininhibitor.

104. A proppant composition for use in hydraulic fracturing, thecomposition comprising: a plurality of particulates; and at least oneparticulate of the plurality of particulates comprising a chemicaltreatment agent, the at least one particulate having a long termpermeability measured in accordance with ISO 13503-5 at 7,500 psi of atleast about 10 Darcies; wherein the at least one chemical treatmentagent separates from the at least one particulate when located inside afracture of a subterranean formation after a period of time.

105. The composition according to paragraph 104, wherein the pluralityof particulates comprises non-porous particulates and porousparticulates.

106. The composition according to paragraph 105, wherein the pluralityof particulates has a permeability that is at least equal to thepermeability of the non-porous particulates.

107. The composition according to paragraph 106, wherein the pluralityof particulates has a conductivity that is at least about 70% of theconductivity of the non-porous particulates.

108. The composition according to paragraph 105, wherein the porousparticulates contain the chemical treatment agent.

109. The composition according to paragraph 105, wherein the non-porousparticulates contain the chemical treatment agent.

110. The composition according to paragraph 105, wherein at least one ofthe non-porous particulates and the porous particulates have an apparentspecific gravity that is less than 3.1 g/cm³.

111. The composition according to paragraph 105, wherein at least one ofthe non-porous particulates and the porous particulates have an apparentspecific gravity of from 3.1 to 3.4 g/cm³.

112. The composition according to paragraph 105, wherein at least one ofthe non-porous particulates and the porous particulates has an apparentspecific gravity that is greater than 3.4 g/cm³.

113. The composition according to paragraph 105, wherein the non-porousparticulate is selected from the group consisting of light weightceramic non-porous proppant, intermediate density ceramic non-porousproppant and high density porous ceramic proppant.

114. The composition according to paragraph 105, wherein the porousparticulate is selected from the group consisting of light weight porousceramic proppant, intermediate density porous ceramic proppant and highdensity porous ceramic proppant.

115. The composition according to any one of paragraphs 104 to 114,wherein the chemical treatment agent is selected from the groupconsisting of scale inhibitors, tracer materials, hydrate inhibitors,hydrogen sulfide scavenging materials, corrosion inhibitors, waxinhibitors, asphaltene inhibitors, organic deposition inhibitors,biocides, demulsifiers, defoamers, gel breakers, salt inhibitors, oxygenscavengers, iron sulfide scavengers, iron scavengers, clay stabilizers,enzymes, biological agents, flocculants, naphthenate inhibitors,carboxylate inhibitors, nanoparticle dispersions, surfactants andcombinations thereof.

116. The composition according to paragraph 115, wherein the tracermaterial comprises a chemical tracer.

117. The composition according to paragraph 116, wherein the chemicaltracer comprises a biological marker.

118. The composition according to paragraph 117, wherein the biologicalmarker comprises DNA.

119. The composition according to paragraph 115, wherein the tracermaterial comprises at least one of metallic and non-metallicnanoparticles.

120. The composition according to paragraph 115, wherein thenanoparticle dispersions alter wettability of the proppant compositionin a hydraulic fracture environment.

121. The composition according to paragraph 115, wherein the surfactantalters wettability of the proppant composition in a hydraulic fractureenvironment.

122. The composition according to any one of paragraphs 105 to 121,wherein the proppant composition further comprises a degradable coatingor a non-degradable coating, and wherein the degradable coating degradesinside the fracture.

123. The composition according to paragraph 122, wherein the degradablecoating is selected from the group consisting of polylactic acid,water-soluble polymers, and cross-linkable water-soluble polymers andany combination thereof.

124. The composition according to paragraph 122, wherein the degradablecoating is a self-polishing coating.

125. The composition according to paragraph 122, wherein thenon-degradable coating is selected from the group consisting of phenolformaldehyde, polyurethane, cellulose ester, polyamides, vinyl esters,and epoxies, and any combination thereof.

126. The composition according to any one of paragraphs 122 to 125,wherein the chemical treatment agent is contained in the non-degradablecoating or the degradable coating.

127. The composition according to any one of paragraphs 122 to 126,wherein the chemical treatment agent is disposed between the at leastone particulate and the non-degradable coating or the degradablecoating.

128. A method of hydraulic fracturing a subterranean formation,comprising: injecting a hydraulic fluid into a subterranean formation ata rate and pressure sufficient to open a fracture therein; and injectinga fluid containing a proppant composition into the fracture, theproppant composition comprising: a plurality of particulates; and atleast one particulate of the plurality of particulates comprising achemical treatment agent, the at least one particulate having a longterm permeability measured in accordance with ISO 13503-5 at 7,500 psiof at least about 10 Darcies; eluting the chemical treatment agent fromthe at least one particulate located inside the fracture over a periodof time.

129. The method according to paragraph 128, wherein the chemicaltreatment agent is selected from the group consisting of tracers, scaleinhibitors, hydrate inhibitors, hydrogen sulfide scavenging materials,corrosion inhibitors, wax inhibitors, asphaltene inhibitors, organicdeposition inhibitors, biocides, demulsifiers, defoamers, gel breakers,salt inhibitors, oxygen scavengers, iron sulfide scavengers, ironscavengers, clay stabilizers, enzymes, biological agents, flocculants,naphthenate inhibitors, carboxylate inhibitors, nanoparticledispersions, surfactants and any other oil field treatment chemical.

130. The method according to paragraph 129, wherein the tracer comprisesa chemical tracer.

131. The method according to paragraph 130, wherein the chemical tracercomprises a biological marker.

132. The method according to paragraph 130, wherein the chemical tracercomprises DNA.

133. The method according to any one of paragraphs 129 to 132, whereinthe nanoparticle dispersions alter wettability of the proppantcomposition in a hydraulic fracture environment.

134. The method according to any one of paragraphs 129 to 133, whereinthe surfactant alters wettability of the proppant composition in ahydraulic fracture environment.

135. The method according to any one of paragraphs 129 to 134, whereinthe proppant composition further comprises a degradable coating or anon-degradable coating and wherein the degradable coating degradesinside the fracture.

136. The method according to paragraph 135, wherein the degradablecoating is selected from the group consisting of polylactic acid,water-soluble polymers and cross-linkable water-soluble polymers.

137. The composition according to paragraph 135, wherein the degradablecoating is a self-polishing coating.

138. The composition according to paragraph 135, wherein thenon-degradable coating is selected from the group consisting of phenolformaldehyde, polyurethane, cellulose ester, polyamides, vinyl esters,and epoxies, and any combination thereof.

139. The composition according to any one of paragraphs 135 to 138,wherein the chemical treatment agent is contained in the non-degradablecoating or the degradable coating.

140. The composition according to any one of paragraphs 135 to 139,wherein the chemical treatment agent is disposed between the at leastone particulate and the non-degradable coating or the degradablecoating.

141. The method according to any one of paragraphs 128 to 140, whereinthe chemical treatment agent elutes from the at least one particulate ata rate of at least about 0.1 ppm/(gram*day) for at least 6 months.

142. A method of diagnostic evaluation of a hydraulic fracturingstimulation of a subterranean formation, comprising: injecting ahydraulic fluid into at least one stage of the subterranean formation ata rate and pressure sufficient to open a fracture therein, thesubterranean formation comprising one or more formation fluids and thehydraulic fluid comprising a proppant composition comprising at leastone particulate containing a biological marker; wherein the biologicalmarker separates from the at least one particulate continuously over aperiod of time; wherein the biological marker returns to the surfacewith the formation fluids; and wherein the biological marker isrecovered and identified.

143. The method according to paragraph 142, wherein the biologicalmarker is DNA.

144. The method according to paragraphs 142 or 143, wherein the at leastone particulate is selected from the group consisting of sand,non-porous ceramic proppant, and porous ceramic proppant and any mixturethereof.

145. The method according to any one of paragraphs 142 to 144, whereinthe biological marker is encapsulated.

146. The method according to paragraph 143, wherein the DNA comprises aspecific sequence of nitrogenous bases that exhibits thermal stabilityqualities that are compatible with the thermal properties of thesubterranean formation.

147. The method according to paragraph 146, wherein the DNA exhibitsthermal stability at a temperature up to about 186 to 221° F., up toabout 222 to 250° F., or up to about 269 to about 292° F.

148. The method according to any one of paragraphs 142 to 147, whereinthe hydraulic fracturing stimulation of the subterranean formation isperformed in a plurality of stages and the proppant composition injectedinto each such stage comprises two or more particulates each containinga unique biological marker, such that no two stages of the subterraneanformation are injected with a proppant composition comprisingparticulates containing the same biological marker.

149. The method according to paragraph 148, further comprising injectinga proppant composition including particulates containing an uniquelyidentifiable biological marker into different segments of a stage of thesubterranean formation, such that no two segments of a stage of thesubterranean formation are injected with proppant compositions includingparticulates containing the same biological marker.

150. The method according to any one of paragraphs 142 to 149, whereinthe biological marker separates from the proppant composition by atleast one of leaching, eluting, diffusing, bleeding, discharging,dissolving, desorbing, draining, seeping, and leaking out of theproppant composition.

151. The method according to any one of paragraphs 142 to 150, whereinthe formation fluids have an aqueous phase and wherein the biologicalmarker separates into the aqueous phase of the formation fluids whenseparating from the at least one particulate.

152. The method according to any one of paragraphs 142 to 151, whereinthe formation fluids have a hydrocarbon phase and wherein the biologicalmarker separates into the hydrocarbon phase of the formation fluids whenseparating from the at least one particulate.

153. The method according to any one of paragraphs 142 to 152, whereinthe biological marker separates from the proppant composition over aperiod of up to about one year after placement of the proppantcomposition in the subterranean formation.

154. The method according to any one of paragraphs 142 to 153, whereinthe biological marker separates from the proppant composition over aperiod of up to about five years after placement of the proppantcomposition in the subterranean formation.

155. The method according to any one of paragraphs 142 to 154, whereinthe biological marker separates from the proppant composition over aperiod of up to about ten years after placement of the proppantcomposition in the subterranean formation.

156. The method according to any one of paragraphs 142 to 155, whereinmultiple uniquely identifiable biological markers from different stagesof the subterranean formation are simultaneously recovered andidentified.

157. The method according to any one of paragraphs 142 to 156, furthercomprising, estimating the relative hydrocarbon or water volumecontribution of a stage or stages of the subterranean formation based onthe relative amounts of uniquely identifiable biological markersrecovered from the stage or stages of the subterranean formation.

158. The method according to any one of paragraphs 142 to 157, furthercomprising, estimating the relative hydrocarbon or water volumecontribution from each segment of a stage of the subterranean formationbased on the amount of uniquely identifiable biological markersrecovered from each segment of a stage of the subterranean formation.

159. The method according to any one of paragraphs 142 to 158, whereinthe biological marker is encapsulated by a polymer.

160. The method according to paragraph 159, wherein the polymer is atleast one member selected from the group consisting of high meltingacrylate-, methacrylate- or styrene-based polymers, block copolymers ofpolylactic-polyglycolic acid, polyglycolics, polylactides, polylacticacid, gelatin, water-soluble polymers, cross-linkable water-solublepolymers, lipids, gels and silicas.

161. The method according to any one of paragraphs 142 to 160, whereinthe proppant composition comprises porous particulates and non-porousparticulates and wherein the porous particulates of the proppantcomposition have an internal interconnected porosity of from about 5 toabout 15% or from about 15 to about 35%.

162. The method according to paragraph 161, wherein the porousparticulates of the proppant composition comprise the biological markerand include a permeable coating.

163. A proppant composition for use in hydraulic fracturing, thecomposition comprising: particulates containing a biological marker;wherein the particulates have a long term permeability measured inaccordance with ISO 13503-5 at 7,500 psi of at least about 10 Darcies;and wherein the biological marker separates from the particulates aftera period of time.

164. The proppant composition according to paragraph 163, wherein theparticulates are selected from the group consisting of sand, non-porousceramic proppant, light weight porous ceramic proppant, intermediatedensity porous ceramic proppant and high density porous ceramicproppant.

165. The proppant composition according to paragraphs 163 or 164,wherein the biological marker is DNA.

166. The proppant composition according to paragraph 165, wherein theDNA comprises a specific sequence of nitrogenous bases that exhibitsthermal stability qualities that are compatible with the thermalproperties of the subterranean formation.

167. The proppant composition according to paragraph 166, wherein theDNA exhibits thermal stability at a temperature up to about 186 to 221°F., up to about 222 to 250° F., or up to about 269 to about 292° F.

168. The proppant composition according to any one of paragraphs 163 to167, wherein the biological marker is encapsulated by a polymer.

169. The proppant composition according to paragraph 168, wherein thepolymer is at least one member selected from the group consisting ofhigh melting acrylate-, methacrylate- or styrene-based polymers, blockcopolymers of polylactic-polyglycolic acid, polyglycolics, polylactides,polylactic acid, gelatin, water-soluble polymers, cross-linkablewater-soluble polymers, lipids, gels and silicas.

170. The proppant composition according to any one of paragraphs 163 to169, wherein the proppant composition comprises porous particulates andnon-porous particulates and wherein the porous particulates have aninternal interconnected porosity of from about 5-15% or from about15-35%.

171. The proppant composition according to any one of paragraphs 163 to170, wherein the proppant composition is injected into a hydraulicallycreated fracture in a subterranean formation.

172. The proppant composition according to paragraph 171, wherein thebiological marker separates from the particulates over a period of up toabout one year after injection of the proppant composition in thehydraulically created fracture in the subterranean formation.

173. The proppant composition according to paragraph 171, wherein thebiological marker separates from the particulates over a period of up toabout five years after injection of the proppant composition in thehydraulically created fracture in the subterranean formation.

174. The proppant composition according to paragraph 171, wherein thebiological marker separates from the particulates over a period of up toabout ten years after injection of the proppant composition in thehydraulically created fracture in the subterranean formation.

175. A method of hydraulically fracturing a subterranean formation,comprising: injecting a hydraulic fluid into a subterranean formation ata rate and pressure sufficient to open a fracture therein; coating oneor more proppant particulates with a chemical treatment agent to provideone or more chemical treatment agent containing proppant particulates;coating the chemical treatment agent containing proppant particulateswith a semi-permeable substantially non-degradable polymer to provideone or more coated proppant particulates; and injecting a fluidcontaining the coated proppant particulates into the subterraneanformation, wherein the chemical treatment agent is released into thesubterranean formation over a period of time.

176. The method according to paragraph 175, further comprising infusingthe one or more proppant particulates with the chemical treatment agentprior to coating the one or more proppant particulates with the chemicaltreatment agent.

177. The method according to paragraphs 175 or 176, wherein the one ormore proppant particulates are selected from the group consisting ofsand, non-porous ceramic particulates, light weight porous ceramicproppant, intermediate density porous ceramic proppant and high densityporous ceramic proppant.

178. The method according to any one of paragraphs 175 to 177, whereinthe chemical treatment agent is selected from the group consisting oftracers, scale inhibitors, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, paraffin inhibitors, waxinhibitors, asphaltene inhibitors, organic deposition inhibitors,biocides, defoamers, gel breakers, salt inhibitors, oxygen scavengers,iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, demulsifiers and combinations thereof.

179. The method according to paragraph 178, wherein the tracer materialcomprises a chemical tracer selected from the group consisting of dyes,fluorescent materials, metallic nano-particles, non-metallicnano-particles and biological markers.

180. The method according to paragraph 179, wherein the chemical tracercomprises DNA.

181. The method according to paragraph 176, wherein the porous ceramicparticulates are infused with the chemical treatment agent by at leastone of vacuum infusion, thermal infusion, capillary action, ribbonblending at room or elevated temperature, microwave blending, and pugmill mixing.

182. The method according to any one of paragraphs 175 to 181, whereinthe semi-permeable substantially non-degradable polymer coating isselected from the group consisting of phenol formaldehyde, polyurethane,cellulose esters, polyamides, vinyl esters, epoxies and combinationsthereof.

183. The method according to any one of paragraphs 175 to 182, whereinthe chemical treatment agent is released into the subterranean formationby at least one of leaching, eluting, diffusing, bleeding, discharging,dissolving, desorbing, draining, seeping, and leaking from the coatedproppant particulates.

184. The method according to paragraph 183, wherein the chemicaltreatment agent is released from the coated proppant particulates over aperiod of up to about ten years after placement of the coated proppantparticulates in the hydraulically created fracture.

185. The method according to paragraph 184, wherein the chemicaltreatment agent is released from the coated proppant particulates over aperiod of up to about five years after placement of the coated proppantparticulates in the hydraulically created fracture.

186. The method according to paragraph 185, wherein the chemicaltreatment agent is released from the coated proppant particulates over aperiod of up to about one year after placement of the coated proppantparticulates in the hydraulically created fracture.

187. A method of hydraulically fracturing a subterranean formation,comprising: injecting a hydraulic fluid into a subterranean formation ata rate and pressure sufficient to open a fracture therein; infusing oneor more proppant particulates with a first chemical treatment agent toprovide one or more infused proppant particulates. coating the infusedproppant particulates with a second chemical treatment agent to provideone or more second chemical treatment agent containing proppantparticulates; coating the second chemical treatment agent containingproppant particulates with a semi-permeable substantially non-degradablepolymer to provide one or more coated proppant particulates; andinjecting a fluid containing the coated proppant particulates into thesubterranean formation, wherein the first and second chemical treatmentagents are released into the subterranean formation over a period oftime.

188. The method according to paragraph 187, wherein the one or moreproppant particulates are selected from the group consisting of sand,non-porous ceramic particulates, light weight porous ceramic proppant,intermediate density porous ceramic proppant and high density porousceramic proppant.

189. The method according to paragraphs 187 or 188, wherein the firstchemical treatment agent is selected from the group consisting oftracers, scale inhibitors, hydrate inhibitors, hydrogen sulfidescavenging materials, corrosion inhibitors, paraffin inhibitors, waxinhibitors, asphaltene inhibitors, organic deposition inhibitors,biocides, defoamers, gel breakers, salt inhibitors, oxygen scavengers,iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, demulsifiers and combinations thereof.

190. The method according to any one of paragraphs 187 to 189, whereinthe second chemical treatment agent is selected from the groupconsisting of tracers, scale inhibitors, hydrate inhibitors, hydrogensulfide scavenging materials, corrosion inhibitors, paraffin inhibitors,wax inhibitors, asphaltene inhibitors, organic deposition inhibitors,biocides, defoamers, gel breakers, salt inhibitors, oxygen scavengers,iron sulfide scavengers, iron scavengers, clay stabilizers, enzymes,biological agents, flocculants, naphthenate inhibitors, carboxylateinhibitors, demulsifiers and combinations thereof.

191. The method according to any one of paragraphs 187 to 190, whereinthe one or more proppant particulates are infused with the firstchemical treatment agent by at least one of vacuum infusion, thermalinfusion, capillary action, ribbon blending at room or elevatedtemperature, microwave blending, and pug mill mixing.

192. The method according to any one of paragraphs 187 to 191, whereinthe semi-permeable substantially non-degradable polymer coating isselected from the group consisting of phenol formaldehyde, polyurethane,cellulose esters, polyamides, vinyl esters, epoxies and combinationsthereof.

While the present invention has been described in terms of severalexemplary embodiments, those of ordinary skill in the art will recognizethat the invention can be practiced with modification within the spiritand scope of the appended claims.

The present disclosure has been described relative to a severalexemplary embodiments. Improvements or modifications that becomeapparent to persons of ordinary skill in the art only after reading thisdisclosure are deemed within the spirit and scope of the application. Itis understood that several modifications, changes and substitutions areintended in the foregoing disclosure and in some instances some featuresof the invention will be employed without a corresponding use of otherfeatures. Accordingly, it is appropriate that the appended claims beconstrued broadly and in a manner consistent with the scope of theinvention.

What is claimed is:
 1. A proppant composition for use in hydraulicfracturing, the composition comprising: a plurality of particulates; anon-degradable coating; and at least one particulate of the plurality ofparticulates comprising a degradable shell encapsulating at least aportion of the non-degradable coating, and a chemical treatment agent,the at least one particulate having a long term permeability measured inaccordance with ISO 13503-5 at 7,500 psi of at least about 10 D; whereinthe particulate is a porous particulate; and wherein the at least onechemical treatment agent separates from the at least one particulatewhen located inside a fracture of a subterranean formation after aperiod of time.
 2. The composition of claim 1, further comprising aplurality of non-coated particulates.
 3. The composition of claim 1,wherein the chemical treatment agent comprises a scale inhibitor.
 4. Thecomposition of claim 3, wherein the scale inhibitor comprisesdiethylenetriamine penta(methylene phosphonic acid).
 5. The compositionof claim 3, wherein the scale inhibitor comprises one or more potassiumsalts of maleic acid copolymers.
 6. The composition of claim 3, whereinthe at least one chemical treatment agent elutes from the plurality ofparticulates at a rate of less than 1 ppm/(gram*day) for at least about2 hours after contacting the subterranean formation and at a rate of atleast about 0.1 ppm/(gram*day) for at least 2 weeks after contacting anaqueous phase solution and/or a hydrocarbon phase solution.
 7. Thecomposition of claim 1, wherein the non-degradable coating has aviscosity of about 1 cP to about 2,200 cP at a temperature of about 25°C.
 8. The composition of claim 7, wherein the non-degradable coating isa phenolic novolac resin.
 9. The composition of claim 7, wherein thechemical treatment agent is mixed with the non-degradable coating. 10.The composition of claim 8, wherein the chemical treatment agent ismixed with the degradable shell.
 11. The composition of claim 1, whereinthe degradable shell comprises one or more water-soluble polymers. 12.The composition of claim 1, wherein the degradable shell is athermoplastic material that degrades at temperatures of from about 25°C. to about 200° C. within a time period ranging from about 10 minutesto about 1,000 hours.
 13. The composition of claim 1, wherein the atleast one chemical treatment agent elutes from the at least oneparticulate at a rate of less than 1 ppm/(gram*day) for at least about 2hours after contacting the subterranean formation.
 14. A method ofhydraulic fracturing a subterranean formation, comprising: injecting ahydraulic fluid into a subterranean formation at a rate and pressuresufficient to open a fracture therein; and injecting a fluid containingthe proppant composition of claim 1 into the fracture.
 15. The method ofclaim 14, wherein the non-degradable coating has a viscosity of about 1cP to about 2,200 cP at a temperature of about 25° C.
 16. The method ofclaim 15, wherein the at least one chemical treatment agent elutes fromthe at least one particulate at a rate of less than 1 ppm/(gram*day) forat least about 2 hours after contacting the subterranean formation, andwherein the chemical treatment agent elutes from the at least oneparticulate in the fracture at a rate of at least about 0.1ppm/(gram*day) for at least 2 weeks.
 17. The composition of claim 1,wherein the porous particulates have an internal interconnected porosityof about 5% to about 75%.
 18. The composition of claim 1, wherein theplurality of particulates have a bulk density of about 1.0 g/cc to about2.1 g/cc.
 19. The composition of claim 11, wherein the water solublepolymers include sodium carboxymethyl cellulose, gum arabic, carrageenangum, karaya gum, xanthan gum, carboxymethyl hydroxypropyl guar, cationicguar, dimethyl ammonium hydrolyzed collagen protein, poly (ethyleneoxide), poly (propylene oxide), poly (ethylene oxide)-poly (propyleneoxide) block copolymers, poly (1,4-oxybutylene) glycol, or poly(alkylene glycol diacrylates).